10-Q
Table of Contents


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2015
OR
[ ] 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, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting   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
¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  YES  ¨   NO  þ
 
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
 
Common stock, par value $1.00 per share, outstanding at January 31, 2016: 84,790,295 shares.


Table of Contents


GLOSSARY OF TERMS
 
Frequently used abbreviations, acronyms, or terms used in this report:
 
National Fuel Gas Companies
 
Company
The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Distribution Corporation
National Fuel Gas Distribution Corporation
Empire
Empire Pipeline, Inc.
Midstream Corporation
National Fuel Gas Midstream Corporation
National Fuel
National Fuel Gas Company
NFR
National Fuel Resources, Inc.
Registrant
National Fuel Gas Company
Seneca
Seneca Resources Corporation
Supply Corporation
National Fuel Gas Supply Corporation
 
Regulatory Agencies
 
CFTC
Commodity Futures Trading Commission
EPA
United States Environmental Protection Agency
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
NYDEC
New York State Department of Environmental Conservation
NYPSC
State of New York Public Service Commission
PaDEP
Pennsylvania Department of Environmental Protection
PaPUC
Pennsylvania Public Utility Commission
SEC
Securities and Exchange Commission
Other
 
2015 Form 10-K
The Company’s Annual Report on Form 10-K for the year ended September 30, 2015
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 pays Supply Corporation and/or Empire for gas the customer receives in excess of amounts delivered into Supply Corporation’s and Empire’s systems by the customer’s shipper.
Degree day
A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative
A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.).  The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract.  Examples include futures contracts, forward contracts, options, no cost collars and swaps.
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

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Table of Contents


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

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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
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.




4

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INDEX
 
Page
 
 
 
 
 
 
 
 
 
6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 3.  Defaults Upon Senior Securities 
 
Item 4.  Mine Safety Disclosures 
 
Item 5.  Other Information 
 
 
 
 
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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Table of Contents


Part I.  Financial Information
 
Item 1.  Financial Statements
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
 
Three Months Ended 
 December 31,
(Thousands of Dollars, Except Per Common Share Amounts)
2015
 
2014
INCOME
 
 
 
Operating Revenues
$
375,195

 
$
523,909

 
 
 
 
Operating Expenses
 
 
 
Purchased Gas
42,068

 
127,091

Operation and Maintenance
112,692

 
112,582

Property, Franchise and Other Taxes
20,357

 
20,929

Depreciation, Depletion and Amortization
70,551

 
102,747

Impairment of Oil and Gas Producing Properties
435,451

 

 
681,119

 
363,349

Operating Income (Loss)
(305,924
)
 
160,560

Other Income (Expense):
 
 
 
Interest Income
1,799

 
1,258

Other Income
2,418

 
1,183

Interest Expense on Long-Term Debt
(30,372
)
 
(22,311
)
Other Interest Expense
(1,380
)
 
(790
)
Income (Loss) Before Income Taxes
(333,459
)
 
139,900

Income Tax Expense (Benefit)
(144,350
)
 
55,160

 
 
 
 
Net Income (Loss) Available for Common Stock
(189,109
)
 
84,740

 
 
 
 
EARNINGS REINVESTED IN THE BUSINESS
 
 
 
Balance at Beginning of Period
1,103,200

 
1,614,361

 
914,091

 
1,699,101

 
 
 
 
Dividends on Common Stock
(33,472
)
 
(32,442
)
Balance at December 31
$
880,619

 
$
1,666,659

 
 
 
 
Earnings Per Common Share:
 
 
 
Basic:
 
 
 
Net Income (Loss) Available for Common Stock
$
(2.23
)
 
$
1.01

Diluted:
 
 
 
Net Income (Loss) Available for Common Stock
$
(2.23
)
 
$
1.00

Weighted Average Common Shares Outstanding:
 
 
 
Used in Basic Calculation
84,651,233

 
84,208,645

Used in Diluted Calculation
84,651,233

 
85,118,516

Dividends Per Common Share:
 
 
 
Dividends Declared
$
0.395

 
$
0.385

See Notes to Condensed Consolidated Financial Statements

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Table of Contents


National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)

                                                      
Three Months Ended 
 December 31,
 
(Thousands of Dollars)                                  
2015
 
2014
 
Net Income (Loss) Available for Common Stock
$
(189,109
)
 
$
84,740

 
Other Comprehensive Income (Loss), Before Tax:


 


 
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
(638
)
 
(412
)
 
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
65,372

 
243,829

 
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income
(57,170
)
 
(24,265
)
 
Other Comprehensive Income (Loss), Before Tax
7,564

 
219,152

 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
(191
)
 
(160
)
 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
20,676

 
102,949

 
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income
(18,005
)
 
(10,089
)
 
Income Taxes – Net
2,480

 
92,700

 
Other Comprehensive Income
5,084

 
126,452

 
Comprehensive Income (Loss)
$
(184,025
)
 
$
211,192

 
 





























See Notes to Condensed Consolidated Financial Statements

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Table of Contents


National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
 
 
December 31,
2015
 
September 30, 2015
(Thousands of Dollars)
 
 
 
ASSETS
 
 
 
Property, Plant and Equipment
$
9,311,376

 
$
9,261,323

Less - Accumulated Depreciation, Depletion and Amortization
4,428,593

 
3,929,428

 
4,882,783

 
5,331,895

Current Assets
 

 
 

Cash and Temporary Cash Investments
36,329

 
113,596

Hedging Collateral Deposits
9,551

 
11,124

Receivables – Net of Allowance for Uncollectible Accounts of $30,946 and $29,029, Respectively
211,112

 
105,004

Unbilled Revenue
40,178

 
20,746

Gas Stored Underground
28,811

 
34,252

Materials and Supplies - at average cost
32,389

 
30,414

Other Current Assets
66,145

 
60,665

           
424,515

 
375,801

 
 
 
 
Other Assets
 

 
 

Recoverable Future Taxes
172,205

 
168,214

Unamortized Debt Expense
2,085

 
2,218

Other Regulatory Assets
275,721

 
278,227

Deferred Charges
16,410

 
15,129

Other Investments
108,209

 
92,990

Goodwill
5,476

 
5,476

Prepaid Post-Retirement Benefit Costs
25,357

 
24,459

Fair Value of Derivative Financial Instruments
277,409

 
270,363

Other                  
162

 
167

                   
883,034

 
857,243

 
 
 
 
Total Assets
$
6,190,332

 
$
6,564,939













See Notes to Condensed Consolidated Financial Statements
 
 

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Table of Contents


National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
                                  
December 31,
2015
 
September 30, 2015
(Thousands of Dollars)
 
 
 
CAPITALIZATION AND LIABILITIES
 
 
 
Capitalization:
 
 
 
Comprehensive Shareholders’ Equity
 
 
 
Common Stock, $1 Par Value
 
 
 
Authorized  - 200,000,000 Shares; Issued And Outstanding – 84,739,068 Shares and 84,594,383 Shares, Respectively
$
84,739

 
$
84,594

Paid in Capital
748,867

 
744,274

Earnings Reinvested in the Business
880,619

 
1,103,200

Accumulated Other Comprehensive Income
98,456

 
93,372

Total Comprehensive Shareholders’ Equity 
1,812,681

 
2,025,440

Long-Term Debt, Net of Unamortized Discount and Debt Issuance Costs
2,084,562

 
2,084,009

Total Capitalization 
3,897,243

 
4,109,449

 
 
 
 
Current and Accrued Liabilities
 

 
 

Notes Payable to Banks and Commercial Paper
31,400

 

Current Portion of Long-Term Debt

 

Accounts Payable
126,917

 
180,388

Amounts Payable to Customers
45,076

 
56,778

Dividends Payable
33,472

 
33,415

Interest Payable on Long-Term Debt
30,285

 
36,200

Customer Advances
23,425

 
16,236

Customer Security Deposits
16,757

 
16,490

Other Accruals and Current Liabilities
95,830

 
96,557

Fair Value of Derivative Financial Instruments
7,969

 
10,076

                                                 
411,131

 
446,140

 
 
 
 
Deferred Credits
 

 
 

Deferred Income Taxes
999,399

 
1,137,962

Taxes Refundable to Customers
94,468

 
89,448

Unamortized Investment Tax Credit
644

 
731

Cost of Removal Regulatory Liability
184,784

 
184,907

Other Regulatory Liabilities
113,187

 
108,617

Pension and Other Post-Retirement Liabilities
205,431

 
202,807

Asset Retirement Obligations
158,108

 
156,805

Other Deferred Credits
125,937

 
128,073

                                                 
1,881,958

 
2,009,350

Commitments and Contingencies 

 

 
 
 
 
Total Capitalization and Liabilities
$
6,190,332

 
$
6,564,939

 
See Notes to Condensed Consolidated Financial Statements

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Table of Contents



National Fuel Gas Company
Consolidated Statements of Cash Flows
(Unaudited)
                                                        
Three Months Ended 
 December 31,
(Thousands of Dollars)                                  
2015
 
2014
OPERATING ACTIVITIES
 

 
 
Net Income (Loss) Available for Common Stock
$
(189,109
)
 
$
84,740

Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
 

 
 

Impairment of Oil and Gas Producing Properties
435,451

 

Depreciation, Depletion and Amortization
70,551

 
102,747

Deferred Income Taxes
(140,013
)
 
33,207

Excess Tax Benefits Associated with Stock-Based Compensation Awards
(226
)
 
(7,667
)
Stock-Based Compensation
960

 
3,078

Other
3,418

 
2,358

Change in:
 

 
 

Hedging Collateral Deposits
1,573

 
(10,734
)
Receivables and Unbilled Revenue
(31,150
)
 
(60,947
)
Gas Stored Underground and Materials and Supplies
3,466

 
9,386

Other Current Assets
(5,254
)
 
(5,635
)
Accounts Payable
(20,784
)
 
19,378

Amounts Payable to Customers
(11,702
)
 
2,249

Customer Advances
7,189

 
1,431

Customer Security Deposits
267

 
630

Other Accruals and Current Liabilities
(14,353
)
 
(6,416
)
Other Assets
885

 
2,142

Other Liabilities
2,904

 
19,132

Net Cash Provided by Operating Activities
114,073

 
189,079

 
 
 
 
INVESTING ACTIVITIES
 

 
 

Capital Expenditures
(186,437
)
 
(244,927
)
Net Proceeds from Sale of Oil and Gas Producing Properties
10,574

 

Other                                             
(15,756
)
 
(1,229
)
Net Cash Used in Investing Activities
(191,619
)
 
(246,156
)
 
 
 
 
FINANCING ACTIVITIES
 

 
 

Changes in Notes Payable to Banks and Commercial Paper
31,400

 
87,300

Excess Tax Benefits Associated with Stock-Based Compensation Awards
226

 
7,667

Dividends Paid on Common Stock
(33,415
)
 
(32,400
)
Net Proceeds from Issuance of Common Stock
2,068

 
1,548

Net Cash Provided by Financing Activities
279

 
64,115

Net Increase (Decrease) in Cash and Temporary Cash Investments 
(77,267
)
 
7,038

 
 
 
 
Cash and Temporary Cash Investments at October 1
113,596

 
36,886

Cash and Temporary Cash Investments at December 31 
$
36,329

 
$
43,924

 
 
 
 
Supplemental Disclosure of Cash Flow Information
 
 
 
Non-Cash Investing Activities:
 

 
 

Non-Cash Capital Expenditures
$
93,983

 
$
101,664

Receivable from Sale of Oil and Gas Producing Properties
$
94,364

 
$

 See Notes to Condensed Consolidated Financial Statements

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Table of Contents


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 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.

Reclassification. Due to the adoption of the authoritative guidance regarding the presentation of deferred income taxes, certain prior year amounts have been reclassified to conform with current year presentation. The Company reclassified Deferred Income Taxes of $137.2 million previously shown as Current Assets to Deferred Income Taxes shown as Deferred Credits on the Consolidated Balance Sheet at September 30, 2015.

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, 2015, 2014 and 2013 that are included in the Company's 2015 Form 10-K.  The consolidated financial statements for the year ended September 30, 2016 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.
 
The earnings for the three months ended December 31, 2015 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2016.  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 Statement of Cash Flows.  For purposes of the Consolidated Statement 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 market, on a LIFO method.  Gas stored underground normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters.  In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.”  Such reserve, which amounted to $1.0 million at December 31, 2015, 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 $169.5 million and $176.3 million at December 31, 2015 and September 30, 2015, 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.

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Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The 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.  The book value of the oil and gas properties exceeded the ceiling at December 31, 2015. As such, the Company recognized a pre-tax impairment charge of $435.5 million for the quarter ended December 31, 2015. A deferred income tax benefit of $182.9 million related to the impairment charge was also recognized for the quarter ended December 31, 2015. In adjusting estimated future cash flows for hedging under the ceiling test at December 31, 2015, estimated future net cash flows were increased by $253.7 million.

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. Under the terms of the agreement, Seneca and IOG will jointly participate in a program that will develop up to 80 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest and is obligated to participate in the first 42 wells, and has a one-time option to participate in the remaining 38 wells that can be exercised on or before July 1, 2016. With respect to the first 42 wells, IOG has committed to fund up to $231 million to develop the joint wells. At December 31, 2015, Seneca recorded $10.6 million of cash, a $94.4 million receivable (which was received in January 2016) and a $105 million reduction of property, plant and equipment in recognition of the first installment of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 42 wells. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (26% net revenue interest) in the first 42 wells. If IOG exercises its option to participate in the remaining 38 wells, IOG has agreed to fund up to an additional $211 million to develop such joint wells. Seneca will retain a 10% royalty and the remaining 20% working interest (28% net revenue interest) in the remaining 38 wells. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.
Accumulated Other Comprehensive Income.  The components of Accumulated Other Comprehensive Income and changes for the three months ended December 31, 2015 and 2014, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): 
 
Gains and Losses on Derivative Financial Instruments
Gains and Losses on Securities Available for Sale
Funded Status of the Pension and Other Post-Retirement Benefit Plans
Total
Three Months Ended December 31, 2015
 
 
 
 
Balance at October 1, 2015
$
157,197

$
5,969

$
(69,794
)
$
93,372

Other Comprehensive Gains and Losses Before Reclassifications
44,696

(447
)

44,249

Amounts Reclassified From Other Comprehensive Income
(39,165
)


(39,165
)
Balance at December 31, 2015
$
162,728

$
5,522

$
(69,794
)
$
98,456

Three Months Ended December 31, 2014
 
 
 
 
Balance at October 1, 2014
$
43,659

$
8,382

$
(56,020
)
$
(3,979
)
Other Comprehensive Gains and Losses Before Reclassifications
140,880

(252
)

140,628

Amounts Reclassified From Other Comprehensive Income
(14,176
)


(14,176
)
Balance at December 31, 2014
$
170,363

$
8,130

$
(56,020
)
$
122,473

 
 
 
 
 


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Table of Contents


Reclassifications Out of Accumulated Other Comprehensive Income.  The details about the reclassification adjustments out of accumulated other comprehensive income for the three months ended December 31, 2015 and 2014 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
Details About Accumulated Other Comprehensive Income (Loss) Components
Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income
Affected Line Item in the Statement Where Net Income (Loss) is Presented
 
Three Months Ended December 31,
 
 
2015
2014
 
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
 
 
     Commodity Contracts

$56,327


$20,036

Operating Revenues
     Commodity Contracts
920

4,229

Purchased Gas
     Foreign Currency Contracts
(77
)

Operation and Maintenance Expense
 
57,170

24,265

Total Before Income Tax
 
(18,005
)
(10,089
)
Income Tax Expense
 

$39,165


$14,176

Net of Tax

Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):
                            
At December 31, 2015
 
At September 30, 2015
 
 
 
 
Prepayments
$
8,727

 
$
10,743

Prepaid Property and Other Taxes
15,143

 
13,709

Federal Income Taxes Receivable
7,120

 

Fair Values of Firm Commitments
16,618

 
15,775

Regulatory Assets
18,537

 
20,438

 
$
66,145

 
$
60,665

 
Other Accruals and Current Liabilities.  The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):
                            
At December 31, 2015
 
At September 30, 2015
 
 
 
 
Accrued Capital Expenditures
$
61,362

 
$
53,652

Regulatory Liabilities
4,695

 
5,346

Reserve for Gas Replacement
976

 

Federal Income Taxes Payable

 
5,686

State Income Taxes Payable
751

 
1,170

Other
28,046

 
30,703

 
$
95,830

 
$
96,557

 
Earnings Per Common Share.  Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.  For purposes of determining earnings per common share, the potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares.  As the Company recognized a net loss for the quarter ended December 31, 2015, the aforementioned securities, amounting to 394,205 securities, were not recognized in the diluted earnings per share calculation for the quarter ended December 31, 2015. For 2014, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method.  Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share.  There were 2,461 securities excluded as being antidilutive for the quarter ended December 31, 2014.

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Stock-Based Compensation.  The Company granted 309,996 performance shares during the quarter ended December 31, 2015. The weighted average fair value of such performance shares was $30.71 per share for the quarter ended December 31, 2015. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied.  Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.
 
Half of the performance shares granted during the quarter ended December 31, 2015 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2015 to September 30, 2018.  The performance goal over the performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”).  Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database.  The number of these performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company.  The fair value of these performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award.  The fair value is recorded as compensation expense over the vesting term of the award.  The other half of the performance shares granted during the quarter ended December 31, 2015 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2015 to September 30, 2018.  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 99,843 non-performance based restricted stock units during the quarter ended December 31, 2015.  The weighted average fair value of such non-performance based restricted stock units was $35.57 per share for the quarter ended December 31, 2015. 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.
 
No stock options, SARs or restricted share awards were granted by the Company during the quarter ended December 31, 2015.

New Authoritative Accounting and Financial Reporting Guidance. In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements and disclosures.

In June 2014, the FASB issued authoritative guidance regarding accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the employee has completed the requisite service period. This authoritative guidance requires that such performance targets that affect vesting be treated as performance conditions, meaning that the performance target should not be factored in the calculation of the award at the grant date. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2017, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

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In July 2015, the FASB issued authoritative guidance simplifying inventory measurement by requiring companies to value inventory at the lower of cost and net realizable value. The authoritative guidance applies to all inventory other than inventory that is measured using last-in, first-out or the retail inventory method. The intention of this authoritative guidance is to eliminate some diversity in practice. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.
    
In November 2015, the FASB issued authoritative guidance simplifying the presentation of deferred income taxes. The authoritative guidance requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The Company early adopted this guidance at December 31, 2015 on a retrospective basis.
    
In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments, financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through other comprehensive income. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2019. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

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.
 
The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of December 31, 2015 and September 30, 2015.  Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over the counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.  
Recurring Fair Value Measures
At fair value as of December 31, 2015
(Thousands of Dollars)   
Level 1
 
Level 2
 
Level 3
 
Netting Adjustments(1)
 
Total(1)
Assets:
 

 
 

 
 

 
 

 
 

Cash Equivalents – Money Market Mutual Funds
$
10,323

 
$

 
$

 
$

 
$
10,323

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
5,350

 

 

 
(5,350
)
 

Over the Counter Swaps – Gas and Oil

 
284,066

 

 
(1,598
)
 
282,468

Foreign Currency Contacts

 

 

 
(5,059
)
 
(5,059
)
Other Investments:
 

 
 

 
 

 
 

 
 

Balanced Equity Mutual Fund
36,096

 

 

 

 
36,096

Fixed Income Mutual Fund
21,980

 

 

 

 
21,980

Common Stock – Financial Services Industry
4,179

 

 

 

 
4,179

Other Common Stock
494

 

 

 

 
494

Hedging Collateral Deposits
9,551

 

 

 

 
9,551

Total                                           
$
87,973

 
$
284,066

 
$

 
$
(12,007
)
 
$
360,032

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
$
11,677

 
$

 
$

 
$
(5,350
)
 
$
6,327

Over the Counter Swaps – Gas and Oil

 
3,240

 

 
(1,598
)
 
1,642

Foreign Currency Contracts

 
5,059

 

 
(5,059
)
 

Total
$
11,677

 
$
8,299

 
$

 
$
(12,007
)
 
$
7,969

Total Net Assets/(Liabilities)
$
76,296

 
$
275,767

 
$

 
$

 
$
352,063

 

15

Table of Contents


Recurring Fair Value Measures
At fair value as of September 30, 2015
(Thousands of Dollars)   
Level 1
 
Level 2
 
Level 3
 
Netting Adjustments(1)
 
Total(1)
Assets:
 

 
 

 
 

 
 

 
 

Cash Equivalents – Money Market Mutual Funds
$
92,196

 
$

 
$

 
$

 
$
92,196

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
6,373

 

 

 
(6,373
)
 

Over the Counter Swaps – Gas and Oil

 
272,335

 
1,791

 
(808
)
 
273,318

Foreign Currency Contracts

 

 

 
(2,955
)
 
(2,955
)
Other Investments:
 

 
 

 
 

 
 

 
 

Balanced Equity Mutual Fund
34,884

 

 

 

 
34,884

Fixed Income Mutual Fund
8,004

 

 

 

 
8,004

Common Stock – Financial Services Industry
4,318

 

 

 

 
4,318

Other Common Stock
450

 

 

 

 
450

Hedging Collateral Deposits
11,124

 

 

 

 
11,124

Total                                           
$
157,349

 
$
272,335

 
$
1,791

 
$
(10,136
)
 
$
421,339

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
$
15,276

 
$

 
$

 
$
(6,373
)
 
$
8,903

Over the Counter Swaps – Gas and Oil

 
1,981

 

 
(808
)
 
1,173

     Foreign Currency Contracts

 
2,955

 

 
(2,955
)
 

Total
$
15,276

 
$
4,936

 
$

 
$
(10,136
)
 
$
10,076

Total Net Assets/(Liabilities)
$
142,073

 
$
267,399

 
$
1,791

 
$

 
$
411,263


(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.
 
Derivative Financial Instruments
 
At December 31, 2015 and September 30, 2015, 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 of $9.6 million at December 31, 2015 and $11.1 million at September 30, 2015, which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at December 31, 2015 and September 30, 2015 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, the majority of the 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 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 derivative financial instruments reported in Level 3 consist of a small portion of the crude oil price swap agreements used in the Company’s Exploration and Production segment at September 30, 2015 that settled prior to December 31, 2015.  The fair value of the Level 3 crude oil price swap agreements was based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). 
 
The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities.  At December 31, 2015, 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.
 

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Table of Contents


The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters ended December 31, 2015 and 2014, respectively. For the quarters ended December 31, 2015 and December 31, 2014, no transfers in or out of Level 1 or Level 2 occurred.  There were no purchases or sales of derivative financial instruments during the periods presented in the tables below.  All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below (amounts in parentheses indicate credits in the derivative asset/liability accounts). 
 
Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)   
 
Total Gains/Losses 
 
 
 
October 1, 2015
Gains/Losses Realized and Included in Earnings
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)
Transfer In/Out of Level 3
December 31, 2015
Derivative Financial Instruments(2)
$
1,791

$
(2,002
)
(1) 
$
211

$

$

 
(1) 
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended December 31, 2015
(2) 
Derivative Financial Instruments are shown on a net basis.
 
 
 
 
 
 
 
Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)   
 
Total Gains/Losses 
 
 
 
October 1, 2014
Gains/Losses Realized and Included in Earnings
Gains/Losses Unrealized and Included in Other Comprehensive Income (Loss)
Transfer In/Out of Level 3
December 31, 2014
Derivative Financial Instruments(2)
$
1,368

$
(3,855
)
(1) 
$
7,824

$

$
5,337


(1) 
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended December 31, 2014
(2) 
Derivative Financial Instruments are shown on a net basis.
 
 
 
 
 
 
 
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): 
 
December 31, 2015
 
September 30, 2015
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-Term Debt
$
2,084,562

 
$
1,970,742

 
$
2,084,009

 
$
2,129,558

 
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.
 

17

Table of Contents


Other Investments.  Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
 
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity and fixed income securities. The values of the insurance contracts amounted to $45.5 million at December 31, 2015 and $45.3 million at September 30, 2015. The fair value of the equity mutual fund was $36.1 million at December 31, 2015 and $34.9 million at September 30, 2015. The gross unrealized gain on this equity mutual fund was $6.0 million at December 31, 2015 and $6.5 million at September 30, 2015.  The fair value of the fixed income mutual fund was $22.0 million at December 31, 2015 and $8.0 million at September 30, 2015. The gross unrealized loss on this fixed income mutual fund was $0.1 million at December 31, 2015. The fair value of the stock of an insurance company was $4.2 million at December 31, 2015 and $4.3 million at September 30, 2015. The gross unrealized gain on this stock was $2.5 million at December 31, 2015 and $2.6 million at September 30, 2015. The insurance contracts and marketable equity 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 ten years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments. The derivative financial instruments held by the Energy Marketing segment are not considered to be material to the Company.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at December 31, 2015 and September 30, 2015.  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 and reclassified into earnings in the period or periods during which the hedged transaction affects earnings.  Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. 

As of December 31, 2015, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:
Commodity
Units

 
Natural Gas
159.6

 Bcf (short positions)
Natural Gas
3.0

 Bcf (long positions)
Crude Oil
1,815,000

 Bbls (short positions)
    
As of December 31, 2015, the Company was hedging a total of $87.5 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).
As of December 31, 2015, the Company had $280.4 million ($162.7 million after tax) of net hedging gains included in the accumulated other comprehensive income balance. It is expected that $189.1 million ($109.7 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transaction are recorded in earnings.
Refer to Note 1, under Accumulated Other Comprehensive Income, for the after-tax gain (loss) pertaining to derivative financial instruments.


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Table of Contents


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2015 and 2014 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended December 31,
Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended December 31,
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended December 31,
 
2015
2014
 
2015
2014
 
2015
2014
Commodity Contracts
$
65,341

$
240,023

Operating Revenue
$
56,327

$
20,036

Operating Revenue
$
137

$
1,460

Commodity Contracts
$
2,213

$
3,806

Purchased Gas
$
920

$
4,229

Not Applicable
$

$

Foreign Currency Contracts
$
(2,182
)
$

Operation and Maintenance Expense
$
(77
)
$

Not Applicable
$

$

Total
$
65,372

$
243,829

 
$
57,170

$
24,265

 
$
137

$
1,460

 
 
 
 
 
 
 
 
 
Fair Value Hedges
 
The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of December 31, 2015, the Company’s Energy Marketing segment had fair value hedges covering approximately 16.7 Bcf (16.4 Bcf of fixed price sales commitments, 0.1 Bcf of fixed price purchase commitments and 0.2 Bcf of commitments related to the withdrawal of storage gas). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.

Derivatives in Fair Value Hedging Relationships
Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the
Three Months Ended December 31, 2015
(In Thousands)
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the
Three Months Ended December 31, 2015
(In Thousands)
Commodity Contracts
Operating Revenues
$
3,920

$
(3,920
)
Commodity Contracts
Purchased Gas
$
(61
)
$
61

 
 
$
3,859

$
(3,859
)
 
Credit Risk
 
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly

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basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions and applicable foreign currency forward contracts with sixteen counterparties of which fifteen are in a net gain position.   On average, the Company had $18.4 million of credit exposure per counterparty in a gain position at December 31, 2015. The maximum credit exposure per counterparty in a gain position at December 31, 2015 was $50.4 million. The Company’s gain position on such derivative financial instruments for certain counterparties exceeded the established thresholds at which the counterparties would be required to post collateral. At December 31, 2015, collateral deposits from counterparties of $35.5 million were posted. These collateral deposits are recorded as a component of Accounts Payable on the Consolidated Balance Sheet.
 
As of December 31, 2015, thirteen of the sixteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required.  At December 31, 2015, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $179.9 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements).  For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at December 31, 2015.    
 
For its exchange traded futures contracts, the Company was required to post $9.6 million in hedging collateral deposits as of December 31, 2015.   As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts 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 components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands): 
                                                         
Three Months Ended 
 December 31,
                                                         
2015
 
2014
Current Income Taxes 
 

 
 

Federal                                              
$
(8,227
)
 
$
16,528

State                                                  
3,890

 
5,425

 
 
 
 
Deferred Income Taxes                                
 

 
 

Federal                                               
(97,705
)
 
26,193

State                                                    
(42,308
)
 
7,014

 
(144,350
)
 
55,160

Deferred Investment Tax Credit                            
(87
)
 
(104
)
 
 
 
 
Total Income Taxes                                      
$
(144,437
)
 
$
55,056

Presented as Follows:
 

 
 

Other Income
(87
)
 
(104
)
Income Tax Expense (Benefit)
(144,350
)
 
55,160

 
 
 
 
Total Income Taxes
$
(144,437
)
 
$
55,056


Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes.  The following is a reconciliation of this difference (in thousands): 
 
Three Months Ended 
 December 31,
 
2015
 
2014
U.S. Income (Loss) Before Income Taxes
$
(333,546
)
 
$
139,796

 
 

 
 

Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%
$
(116,741
)
 
$
48,929

State Income Taxes (Benefit)
(24,972
)
 
8,085

Miscellaneous
(2,724
)
 
(1,958
)
 
 
 
 
Total Income Taxes
$
(144,437
)
 
$
55,056

 
On December 18, 2015, President Obama signed into law the Protecting Americans from Tax Hikes Act of 2015, which did not have a significant impact on total income tax expense.

Note 5 - Capitalization
 
Common Stock.  During the three months ended December 31, 2015, the Company issued 52,000 original issue shares of common stock as a result of stock option and SARs exercises and 60,650 original issue shares of common stock for restricted stock units that vested.  In addition, the Company issued 32,113 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 31,810 original issue shares of common stock for the Company’s 401(k) plans.  The Company also issued 4,200 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the three months ended December 31, 2015.  Holders of stock options, SARs, restricted share awards or restricted stock units will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes.  During the three months ended December 31, 2015, 36,088 shares of common stock were tendered to the Company for

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such purposes.  The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
 
Current Portion of Long-Term Debt.    None of the Company’s long-term debt at December 31, 2015 will mature within the following twelve-month period.

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 December 31, 2015, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be approximately $9.6 million.  The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 12 years.

The Company's estimated liability for clean-up costs discussed above includes a $8.4 million estimated liability to remediate a former manufactured gas plant site located in New York. In February 2009, the Company received approval from the NYDEC of a Remedial Design Work Plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. As a result of this work, the Company submitted to the NYDEC a proposal to amend the NYDEC’s Record of Decision remedy for the site.  In April 2013, the NYDEC approved the Company’s proposed amendment.  Final remedial design work for the site was completed, and active remedial work is nearing completion. 
 
The Company 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.
 
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 2015 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 2015 Form 10-K.  A listing of segment assets at December 31, 2015 and September 30, 2015 is shown in the tables below.  
Quarter Ended December 31, 2015 (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
$151,965
$53,354
$125
$143,848
$24,984
$374,276
$706
$213
$375,195
Intersegment Revenues
$—
$22,183
$18,640
$3,664
$311
$44,798
$—
$(44,798)
$—
Segment Profit: Net Income (Loss)
$(237,086)
$21,276
$4,921
$18,606
$1,223
$(191,060)
$189
$1,762
$(189,109)

 


 





 
 
 
 
 
 
 
 
 
 

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(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 December 31, 2015
$2,103,633
$1,597,432
$467,220
$1,930,977
$87,870
$6,187,132
$78,293
$(75,093)
$6,190,332
At September 30, 2015
$2,439,801
$1,590,525
$444,358
$1,934,730
$90,676
$6,500,090
$77,350
$(12,501)
$6,564,939

Quarter Ended December 31, 2014 (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
$204,665
$51,745
$146
$210,073
$56,166
$522,795
$884
$230
$523,909
Intersegment Revenues
$—
$21,461
$24,428
$4,534
$206
$50,629
$—
$(50,629)
$—
Segment Profit: Net Income (Loss)
$26,720
$20,778
$11,623
$22,594
$2,826
$84,541
$(6)
$205
$84,740
 
 
 
 
 
 
 
 
 
 

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 December 31,
2015
2014
 
2015
2014





 




Service Cost
$
2,928

$
3,012

 
$
583

$
673

Interest Cost
10,579

10,304

 
5,096

4,821

Expected Return on Plan Assets
(14,842
)
(14,904
)
 
(7,883
)
(8,522
)
Amortization of Prior Service Cost (Credit)
308

46

 
(228
)
(478
)
Amortization of Losses
8,062

9,032

 
1,382

1,037

Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)
1,906

1,292

 
4,121

4,920






 




Net Periodic Benefit Cost
$
8,941

$
8,782

 
$
3,071

$
2,451

 
 
 
 
 
 
(1) 
The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.
 
Employer Contributions.    During the three months ended December 31, 2015, the Company contributed $4.0 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $0.7 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits.  In the remainder of 2016, the Company expects its contributions to the Retirement Plan to be in the range of $1.0 million to $6.0 million.  In the remainder of 2016, the Company expects to contribute approximately $2.0 million to its VEBA trusts and 401(h) accounts.

Note 9 – Regulatory Matters
    
Following negotiations and other proceedings, on December 6, 2013, Distribution Corporation filed an agreement, also executed by the Department of Public Service and intervenors, extending existing rates through, at a minimum, September 30, 2015. Although customer rates were not changed, the parties agreed that the allowed rate of return on equity would be set, for ratemaking purposes, at 9.1%.  Following conventional practice in New York, the agreement authorizes an “earnings sharing mechanism” (“ESM”).  The ESM distributes earnings above the allowed rate of return as follows:  from 9.5% to 10.5%, 50% would be allocated to shareholders, and 50% will be deferred for the benefit of customers; above 10.5%, 20% would be allocated to shareholders and 80% will be deferred for the benefit of customers.  The agreement further authorizes, and rates reflect, an

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increase in Distribution Corporation’s pipeline replacement spending by $8.2 million per year of the agreement.  The agreement contains other terms and conditions of service that are customary for settlement agreements recently approved by the NYPSC.  A $7.5 million refund provision was passed back to ratepayers during 2014 after the NYPSC approved the settlement agreement without modification in an order issued on May 8, 2014. All significant terms of the agreement, including existing rates, continue in effect beyond September 30, 2015 until modified by the NYPSC. The agreement also states that nothing in the agreement precludes the parties from meeting to discuss extending the agreement on mutually acceptable terms, and presenting such extension to the NYPSC for approval. On May 22, 2015, Distribution Corporation filed with the NYPSC a Notice of Impending Settlement Discussions stating that settlement discussions would be scheduled in the near future, and that such discussions might include, among other things, the possible extension of the agreement on mutually acceptable terms, and on October 21, 2015, Distribution Corporation filed with the NYPSC a Supplemental Notice of Impending Settlement Discussions. In the event settlement is not reached, nothing prevents Distribution Corporation from continuing to operate under the existing agreement or from filing a rate case.
FERC Rate Proceedings
On November 13, 2015, FERC approved Supply Corporation's rate case settlement that extends Supply Corporation's current FERC-approved rate case settlement, requires a rate case filing no later than December 31, 2019 and prohibits any party from seeking to initiate a rate case proceeding before September 30, 2017. Prior to this new extension settlement, Supply Corporation had been otherwise required by its existing rate settlement to make a general rate filing no later than January 1, 2016. The new extension settlement provides, among other things, that Supply Corporation reduce its maximum reservation, capacity, demand and deliverability rates by 2% effective November 1, 2015, and further reduce those rates by an additional 2% on November 1, 2016. Pursuant to the new extension settlement, Supply Corporation also adopted a mechanism that allows it to recover, as a surcharge, certain pipeline safety and greenhouse gas costs it may incur as a result of new rules and regulations.

Empire does not have a rate case currently on file with the FERC, but by order dated January 21, 2016, the FERC began a NGA Section 5 rate review of Empire's rates. By that order, Empire is required to file a Cost and Revenue Study within 75 days (by April 5, 2016).



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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 in the Marcellus 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 Marcellus Shale to markets in Canada and the eastern United States. The Company also develops and produces oil reserves, primarily in California. The Company reports financial results for five business segments.
For the quarter ended December 31, 2015, the Company recorded a loss of $189.1 million.  The loss is driven largely by an impairment charge of $435.5 million ($252.6 million after-tax) recorded in the Exploration and Production segment during the quarter ended December 31, 2015. 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. Such costs are subject to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. Due to significant declines in crude oil and natural gas commodity prices, the book value of the Company’s oil and gas properties exceeded the ceiling at December 31, 2015, resulting in the impairment charge mentioned above. Given the current commodity price environment, the Company expects to record additional significant ceiling test impairments during each of the remaining quarters of fiscal 2016. For further discussion of the ceiling test and a sensitivity analysis concerning changes in crude oil and natural gas commodity prices and their impact on the ceiling test, refer to the Critical Accounting Estimates section below. For further discussion of the Company’s earnings, refer to the Results of Operations section below.
The Company continues to develop its natural gas reserves in the 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.  The Company controls the natural gas interests associated with approximately 785,000 net acres within the Marcellus Shale area, with a majority of the interests held in fee, carrying no royalty and no lease expirations.
As part of its development program for the Marcellus Shale, the Company’s exploration and production subsidiary, Seneca, entered into an asset-level joint development agreement in December 2015 with IOG CRV-Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC. The agreement focuses on the joint development of Marcellus Shale natural gas assets located in Elk, McKean and Cameron counties in north-central Pennsylvania. Under the terms of the agreement, Seneca and IOG will jointly participate in a program that will develop up to 80 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80 percent working interest and is obligated to participate in the first 42 wells, and has a one-time option to participate in the remaining 38 wells that can be exercised on or before July 1, 2016. With respect to the first 42 wells, IOG has committed to fund up to $231 million to develop the joint wells. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5 percent royalty interest and the remaining 20 percent working interest (26 percent net revenue interest) in the first 42 wells. If IOG exercises its option to participate in the 38 wells, IOG would fund up to an additional $211 million to develop such joint wells, and Seneca would retain a 10 percent royalty and the remaining 20 percent working interest (28 percent net revenue interest) in those wells. Seneca’s working interest will increase to 85 percent after IOG achieves a 15 percent internal rate of return.
Given the current low commodity price environment and the joint development agreement discussed above, the Company has reduced its forecasted 2016 capital expenditures in the Exploration and Production segment from approximately $425 million to approximately $175 million, which is net of a $105 million reimbursement from IOG for costs Seneca previously incurred to develop a portion of the first 42 wells under the joint development agreement.
The Company has also reduced forecasted 2016 capital expenditures for its Pipeline and Storage segment and Gathering segment. Capital expenditures in the Pipeline and Storage segment for 2016 are estimated to be $150 million, a decrease from the previously reported $525 million almost entirely attributable to the delay in the Northern Access 2016 project to a new in-service date of November 2017 from its originally targeted late 2016 in-service date. Capital expenditures in the Gathering segment for 2016 are estimated to be $90 million, a decrease from the previously reported $140 million. The decrease is related to fewer gathering facility requirements as a result of the decrease in capital expenditure activity for the Exploration and Production segment.

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Under the Company’s existing 1974 indenture covenants, given the significant ceiling test impairments recorded during the year ended September 30, 2015 and the quarter ended December 31, 2015, the Company is precluded from issuing additional long-term unsecured indebtedness until the second quarter of fiscal 2017. Given the current commodity price environment, the Company expects to record additional significant ceiling test impairments during each of the remaining quarters of fiscal 2016. As a result, the Company would be precluded from issuing incremental long-term debt throughout much of fiscal 2017. However, with the reduction in forecasted capital expenditures discussed above, the Company does not anticipate a need for the issuance of additional long-term debt during fiscal 2016. The Company expects to use cash from operations and, if necessary, short-term borrowings to meet its capital expenditure needs for fiscal 2016. As for fiscal 2017, the Company does not expect to issue incremental long-term debt during that period and would anticipate using cash from operations and short-term borrowings under its revolving credit facility. The Company does not have any long-term debt maturing until fiscal 2018. The 1974 indenture would not preclude the Company from issuing new long-term debt to replace maturing long-term debt. 

CRITICAL ACCOUNTING ESTIMATES
 
For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2015 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.  The book value of the oil and gas properties exceeded the ceiling at December 31, 2015, resulting in an impairment charge of $435.5 million ($252.6 million after-tax) for the quarter ended December 31, 2015. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended December 31, 2015, based on posted Midway Sunset prices, was $45.85 per Bbl.  The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2015, based on the quoted Henry Hub spot price for natural gas, was $2.59 per MMBtu.  (Note – because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended December 31, 2015.)  The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at December 31, 2015 if natural gas prices were $0.25 per MMBtu lower than the average used at December 31, 2015, the additional impairment the Company would have recorded at December 31, 2015 if crude oil prices were $5 per Bbl lower than the average used at December 31, 2015, and the additional impairment that the Company would have recorded at December 31, 2015 if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at December 31, 2015 (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
 
 
 
 
 
 
Calculated Impairment under Sensitivity Analysis
$
381.2

 
$
293.3

 
$
421.9

Actual Impairment Recorded at December 31, 2015
252.6

 
252.6

 
252.6

Additional Impairment
$
128.6

 
$
40.7

 
$
169.3


Looking ahead, the first day of the month Midway Sunset price for crude oil in January 2016 was $30.98 per Bbl. The first day of the month Henry Hub spot price for natural gas in January 2016 was $2.31 per MMBtu. Given these January prices, the potential that prices could stay at this level in future months, and the expected loss of significantly higher oil and gas prices from the 12-month average that will be used in the ceiling test at March 31, 2016, June 30, 2016 and September 30, 2016, the Company expects to experience significant ceiling test impairments in each of those quarters. For a more complete discussion of

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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 2015 Form 10-K.
 
RESULTS OF OPERATIONS
 
Earnings
 
The Company recorded a loss of $189.1 million for the quarter ended December 31, 2015 compared to earnings of $84.7 million for the quarter ended December 31, 2014.  The decrease in earnings is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Gathering segment, Utility segment and Energy Marketing segment also contributed to the decrease. Higher earnings in the Pipeline and Storage segment and the Corporate and All Other categories partially offset these decreases.     
    
The Company's earnings for the quarter ended December 31, 2015 include a non-cash impairment charge of $435.5 million ($252.6 million after-tax) recorded during the quarter ended December 31, 2015 for the Exploration and Production segment's oil and gas producing properties, as discussed above. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.  Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.
 
Earnings (Loss) by Segment
 
Three Months Ended 
 December 31,
(Thousands)
2015
2014
Increase (Decrease)
Exploration and Production
$
(237,086
)
$
26,720

$
(263,806
)
Pipeline and Storage
21,276

20,778

498

Gathering
4,921

11,623

(6,702
)
Utility
18,606

22,594

(3,988
)
Energy Marketing
1,223

2,826

(1,603
)
Total Reportable Segments
(191,060
)
84,541

(275,601
)
All Other
189

(6
)
195

Corporate
1,762

205

1,557

Total Consolidated
$
(189,109
)
$
84,740

$
(273,849
)
 
Exploration and Production
 
Exploration and Production Operating Revenues
 
 
Three Months Ended 
 December 31,
(Thousands)
2015
2014
Increase (Decrease)
Gas (after Hedging)
$
106,174

$
141,657

$
(35,483
)
Oil (after Hedging)
44,730

60,166

(15,436
)
Gas Processing Plant
636

1,058

(422
)
Other
425

1,784

(1,359
)
 
$
151,965

$
204,665

$
(52,700
)
 

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Production Volumes
 
Three Months Ended 
 December 31,
 
2015
2014
Increase (Decrease)
Gas Production (MMcf)
 
 
 
Appalachia
32,788

42,798

(10,010
)
West Coast
783

773

10

Total Production
33,571

43,571

(10,000
)
 
 
 
 
Oil Production (Mbbl)
 
 
 
Appalachia
6

9

(3
)
West Coast
742

762

(20
)
Total Production
748

771

(23
)

Average Prices
 
Three Months Ended 
 December 31,
 
2015
2014
Increase (Decrease)
Average Gas Price/Mcf
 
 
 
Appalachia
$
1.98

$
2.95

$
(0.97
)
West Coast
$
3.65

$
5.61

$
(1.96
)
Weighted Average
$
2.02

$
3.00

$
(0.98
)
Weighted Average After Hedging
$
3.16

$
3.25

$
(0.09
)
 
 
 
 
Average Oil Price/Bbl
 
 
 
Appalachia
$
39.78

$
75.56

$
(35.78
)
West Coast
$
36.05

$
66.86

$
(30.81
)
Weighted Average
$
36.08

$
66.96

$
(30.88
)
Weighted Average After Hedging
$
59.76

$
78.09

$
(18.33
)
 
 
2015 Compared with 2014
 
Operating revenues for the Exploration and Production segment decreased $52.7 million for the quarter ended December 31, 2015 as compared with the quarter ended December 31, 2014.  Gas production revenue after hedging decreased $35.5 million primarily due a decrease in production due to pricing-related curtailments and a $0.09 per Mcf decrease in the weighted average price of gas after hedging. Oil production revenue after hedging decreased $15.4 million due to an $18.33 per Bbl decrease in the weighted average price of oil after hedging coupled with a slight decrease in crude oil production. Processing plant revenue decreased $0.4 million, largely due to a decrease in the price of natural gas liquids and other price and volume fluctuations. In addition, other revenue decreased $1.4 million primarily due to mark-to-market adjustments related to hedging ineffectiveness that occurred during the quarter ended December 31, 2014 that did not recur during the quarter ended December 31, 2015.

The Exploration and Production segment's loss for the quarter ended December 31, 2015 was $237.1 million, a decrease of $263.8 million when compared with earnings of $26.7 million for the quarter ended December 31, 2014.  The main drivers of the decrease were the aforementioned impairment charge ($252.6 million), lower crude oil prices after hedging ($8.9 million), lower natural gas prices after hedging ($1.9 million), lower natural gas production ($21.1 million), lower crude oil production ($1.1 million), the impact of mark-to-market adjustments ($0.9 million), higher interest expense ($2.8 million), and higher operating expenses ($3.0 million). The increase in interest expense was largely due to the Exploration and Production segment's share of the Company's $450 million long-term debt issuance in June 2015. The increase in operating expenses was largely due to an

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increase in professional services associated with Marcellus Shale drilling joint development agreement with IOG in December 2015. These decreases in earnings were partially offset by the impact of lower depletion expense ($23.4 million) and lower production costs ($5.1 million). The decrease in depletion expense is primarily due to the impact of impairment charges recognized in fiscal 2015, a decrease in production due to pricing related curtailments. The decrease in production costs is primarily due to the decrease in transportation costs associated with production volumes transported by Midstream Corporation due to pricing-related curtailments.

Pipeline and Storage
 
Pipeline and Storage Operating Revenues
 
Three Months Ended 
 December 31,
(Thousands)
2015
2014
Increase (Decrease)
Firm Transportation
$
56,505

$
54,193

$
2,312

Interruptible Transportation
975

747

228

 
57,480

54,940

2,540

Firm Storage Service
17,278

17,489

(211
)
Interruptible Storage Service
50

1

49

Other
729

776

(47
)
                
$
75,537

$
73,206

$
2,331

 
Pipeline and Storage Throughput
 
Three Months Ended 
 December 31,
(MMcf)
2015
2014
Increase (Decrease)
Firm Transportation
175,832

186,322

(10,490
)
Interruptible Transportation
5,631

2,102

3,529

 
181,463

188,424

(6,961
)
 
2015 Compared with 2014
 
Operating revenues for the Pipeline and Storage segment increased $2.3 million for the quarter ended December 31, 2015 as compared with the quarter ended December 31, 2014.  The increase was primarily due to an increase in transportation revenues of $2.5 million.  The increase in transportation revenues was largely due to demand charges for transportation service from Supply Corporation’s Westside Expansion and Modernization Project, Supply Corporation's Northern Access 2015 project, which were both fully placed in service during the first quarter of fiscal 2016 and Empire's Tuscarora Lateral Project, which was placed in service in November 2015. Partially offsetting the increase was a decline in operating revenues as a result of a 2% reduction in Supply Corporation's rates associated with the rate case settlement, which became effective November 1, 2015.
            
Transportation volume for the quarter ended December 31, 2015 decreased by 7.0 Bcf from the prior year’s quarter due to warmer weather. Volume fluctuations, other than those caused by the addition or deletion of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2015 were $21.3 million, an increase of $0.5 million when compared with earnings of $20.8 million for the quarter ended December 31, 2014.  The increase in earnings is primarily due to the earnings impact of higher transportation revenues of $1.7 million, as discussed above, combined with an increase in the allowance for funds used during construction (equity component) of $1.0 million. The increase in the allowance for funds used during construction is mainly due to capital costs incurred during the quarter ended December 31, 2015 related to various expansion projects that were under construction. These earnings increases were partially offset by an increase in depreciation expense ($0.8 million) and higher interest expense ($1.0 million). The increase in depreciation expense was attributable to projects that were placed in service within the last year. The increase in interest expense was largely due to Supply Corporation's share of the Company's $450 million long-term debt issuance in June 2015.
        

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Gathering
 
Gathering Operating Revenues
 
Three Months Ended 
 December 31,
(Thousands)
2015
2014
Increase (Decrease)
Gathering
$
18,640

$
24,428

$
(5,788
)
Processing and Other Revenues
125

146

(21
)
 
$
18,765

$
24,574

$
(5,809
)

Gathering Volume
 
Three Months Ended 
 December 31,
 
2015
2014
Increase (Decrease)
Gathered Volume - (MMcf)
33,800

44,872

(11,072
)
 
2015 Compared with 2014
 
Operating revenues for the Gathering segment decreased $5.8 million for the quarter ended December 31, 2015 as compared with the quarter ended December 31, 2014. This decrease was due to a decrease in gathering revenues driven by an 11.1 Bcf decrease in gathered volume.  The overall decrease in gathered volume was largely due to a 12.8 Bcf decrease in gathered volume on Midstream Corporation’s Trout Run Gathering System (Trout Run), a 4.8 Bcf decrease in gathered volume on Midstream Corporation’s Covington Gathering System (Covington). Most of these decreases in gathered volume are attributable to a decrease in Seneca's Marcellus Shale production largely due to pricing related curtailments. These decreases in gathered volume were partially offset by a 6.8 Bcf increase in gathered volume on Midstream Corporation's Clermont Gathering System (Clermont). This increase in gathered volume is primarily attributable to increased usage of the Clermont Gathering System due to the completion of the Northern Access 2015 project in November and December 2015.
         
The Gathering segment’s earnings for the quarter ended December 31, 2015 were $4.9 million, a decrease of $6.7 million when compared with earnings of $11.6 million for the quarter ended December 31, 2014.  The decrease in earnings is mainly due to the earnings impact of lower gathering revenues ($3.8 million), higher interest expense ($1.8 million) and higher depreciation expense ($1.4 million).  The decrease in gathering revenues is due to the decreases in gathered volume in Trout Run, Covington and Mt. Jewett, partially offset by the increase in gathered volume in Clermont, as discussed above. The increase in interest expense is largely due to the Gathering segment's share of the Company's $450 million long-term debt issuance in June 2015 coupled with a decrease in capitalized interest, which was due to various Clermont projects being placed in service.  A large increase in plant balances (largely due to various Clermont projects being placed in service) led to an increase in depreciation expense.
        

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Utility

Utility Operating Revenues
 
Three Months Ended 
 December 31,
(Thousands)
2015
2014
Increase (Decrease)
Retail Sales Revenues:
 
 
 
Residential
$
98,451

$
146,686

$
(48,235
)
Commercial
12,105

18,297

(6,192
)
Industrial 
490

751

(261
)
 
111,046

165,734

(54,688
)
Transportation      
33,902

39,888

(5,986
)
Off-System Sales

5,924

(5,924
)
Other
2,564

3,061

(497
)
                
$
147,512

$
214,607

$
(67,095
)

Utility Throughput
 
Three Months Ended 
 December 31,
(MMcf)
2015
2014
Increase (Decrease)
Retail Sales:
 
 
 
Residential
13,133

16,467

(3,334
)
Commercial
1,827

2,284

(457
)
Industrial 
66

89

(23
)
 
15,026

18,840

(3,814
)
Transportation      
17,615

20,949

(3,334
)
Off-System Sales