NATIONAL FUEL GAS CO, 10-Q filed on 8/5/2016
Quarterly Report
Document And Entity Information
9 Months Ended
Jun. 30, 2016
Jul. 31, 2016
Document And Entity Information [Abstract]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Jun. 30, 2016 
 
Document Fiscal Year Focus
2016 
 
Document Fiscal Period Focus
Q3 
 
Entity Registrant Name
NATIONAL FUEL GAS CO 
 
Entity Central Index Key
0000070145 
 
Current Fiscal Year End Date
--09-30 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
84,988,442 
Trading Symbol
nfg 
 
Consolidated Statements Of Income And Earnings Reinvested In The Business (Unaudited) (USD $)
In Thousands, except Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
INCOME
 
 
 
 
Operating Revenues
$ 335,617 
$ 339,815 
$ 1,159,943 
$ 1,459,851 
Operating Expenses:
 
 
 
 
Purchased Gas
23,477 
27,038 
147,168 
344,728 
Property, Franchise and Other Taxes
20,261 
22,717 
61,923 
68,561 
Depreciation, Depletion and Amortization
58,802 
79,865 
193,300 
265,298 
Impairment of Oil and Gas Producing Properties
82,658 
588,712 
915,552 
709,060 
Total Operating Expenses
290,456 
829,029 
1,657,706 
1,744,172 
Operating Income (Loss)
45,161 
(489,214)
(497,763)
(284,321)
Other Income (Expense):
 
 
 
 
Interest Income
564 
327 
2,640 
1,631 
Other Income
1,519 
2,066 
7,173 
4,638 
Interest Expense on Long-Term Debt
(28,897)
(22,213)
(88,263)
(66,900)
Other Interest Expense
(1,321)
(1,007)
(3,938)
(3,382)
Income (Loss) Before Income Taxes
17,026 
(510,041)
(580,151)
(348,334)
Income Tax Expense (Benefit)
8,740 
(216,907)
(251,641)
(156,610)
Net Income (Loss) Available for Common Stock
8,286 
(293,134)
(328,510)
(191,724)
EARNINGS REINVESTED IN THE BUSINESS
 
 
 
 
Balance at Beginning of Period
699,399 
1,650,840 
1,103,200 
1,614,361 
Beginning Retained Earnings Unappropriated And Current Period Net Income Loss
707,685 
1,357,706 
774,690 
1,422,637 
Dividends on Common Stock
(34,404)
(33,388)
(101,409)
(98,319)
Balance at June 30
673,281 
1,324,318 
673,281 
1,324,318 
Earnings Per Common Share, Basic:
 
 
 
 
Net Income (Loss) Available for Common Stock (in dollars per share)
$ 0.10 
$ (3.47)
$ (3.87)
$ (2.27)
Earnings Per Common Share, Diluted:
 
 
 
 
Net Income (Loss) Available for Common Stock (in dollars per share)
$ 0.10 
$ (3.44)
$ (3.87)
$ (2.25)
Weighted Average Common Shares Outstanding:
 
 
 
 
Used in Basic Calculation (shares)
84,917,664 
84,453,602 
84,791,447 
84,326,182 
Used in Diluted Calculation (shares)
85,470,216 
85,248,281 
84,791,447 
85,237,514 
Dividends Per Common Share:
 
 
 
 
Dividends Declared (in dollars per share)
$ 0.405 
$ 0.395 
$ 1.195 
$ 1.165 
Utility and Energy Marketing [Member]
 
 
 
 
INCOME
 
 
 
 
Operating Revenues
123,976 
132,422 
540,981 
772,802 
Operating Expenses:
 
 
 
 
Operation and Maintenance
46,616 
44,263 
151,474 
156,724 
Exploration and Production and Other [Member]
 
 
 
 
INCOME
 
 
 
 
Operating Revenues
158,578 
160,256 
456,032 
532,173 
Operating Expenses:
 
 
 
 
Operation and Maintenance
35,427 
46,162 
123,965 
140,564 
Pipeline and Storage and Gathering [Member]
 
 
 
 
INCOME
 
 
 
 
Operating Revenues
53,063 
47,137 
162,930 
154,876 
Operating Expenses:
 
 
 
 
Operation and Maintenance
$ 23,215 
$ 20,272 
$ 64,324 
$ 59,237 
Consolidated Statements Of Comprehensive Income (Unaudited) (USD $)
In Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Jun. 30, 2016
Jun. 30, 2015
Jun. 30, 2016
Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
 
 
 
 
Net Income (Loss) Available for Common Stock
$ 8,286 
$ (293,134)
$ (328,510)
$ (191,724)
Other Comprehensive Income (Loss), Before Tax:
 
 
 
 
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
376 
90 
(266)
(56)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
(70,363)
(9,483)
28,777 
295,511 
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income
(388)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income
(58,373)
(50,875)
(176,779)
(129,270)
Other Comprehensive Income (Loss), Before Tax
(128,360)
(60,268)
(148,656)
166,185 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
122 
33 
(85)
(27)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
(29,521)
(4,060)
5,345 
124,792 
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income
(163)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income
(24,514)
(21,800)
(68,120)
(54,807)
Income Taxes – Net
(53,913)
(25,827)
(63,023)
69,958 
Other Comprehensive Income (Loss)
(74,447)
(34,441)
(85,633)
96,227 
Comprehensive Income (Loss)
$ (66,161)
$ (327,575)
$ (414,143)
$ (95,497)
Consolidated Balance Sheets (Unaudited) (USD $)
In Thousands, unless otherwise specified
Jun. 30, 2016
Sep. 30, 2015
ASSETS
 
 
Property, Plant and Equipment
$ 9,460,444 
$ 9,261,323 
Less - Accumulated Depreciation, Depletion and Amortization
5,012,690 
3,929,428 
Property, Plant and Equipment, Net, Total
4,447,754 
5,331,895 
Current Assets
 
 
Cash and Temporary Cash Investments
105,567 
113,596 
Hedging Collateral Deposits
3,008 1
11,124 1
Receivables – Net of Allowance for Uncollectible Accounts of $27,413 and $29,029, Respectively
140,911 
105,004 
Unbilled Revenue
14,604 
20,746 
Gas Stored Underground
15,944 
34,252 
Materials and Supplies - at average cost
33,039 
30,414 
Unrecovered Purchased Gas Costs
933 
Other Current Assets
47,118 
60,665 
Total Current Assets
361,124 
375,801 
Other Assets
 
 
Recoverable Future Taxes
172,456 
168,214 
Unamortized Debt Expense
1,821 
2,218 
Other Regulatory Assets
269,343 
278,227 
Deferred Charges
17,968 
15,129 
Other Investments
111,385 
92,990 
Goodwill
5,476 
5,476 
Prepaid Post-Retirement Benefit Costs
27,158 
24,459 
Fair Value of Derivative Financial Instruments
126,596 
270,363 
Other
116 
167 
Total Other Assets
732,319 
857,243 
Total Assets
5,541,197 
6,564,939 
Capitalization:
 
 
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 84,948,691 Shares and 84,594,383 Shares, Respectively
84,949 
84,594 
Paid in Capital
761,673 
744,274 
Earnings Reinvested in the Business
673,281 
1,103,200 
Accumulated Other Comprehensive Income
7,739 
93,372 
Total Comprehensive Shareholders’ Equity
1,527,642 
2,025,440 
Long-term Debt, Net of Unamortized Discount and Debt Issuance Costs
2,085,686 
2,084,009 
Total Capitalization
3,613,328 
4,109,449 
Current and Accrued Liabilities
 
 
Notes Payable to Banks and Commercial Paper
Current Portion of Long-Term Debt
Accounts Payable
86,487 
180,388 
Amounts Payable to Customers
35,441 
56,778 
Dividends Payable
34,404 
33,415 
Interest Payable on Long-Term Debt
28,985 
36,200 
Customer Advances
38 
16,236 
Customer Security Deposits
16,094 
16,490 
Other Accruals and Current Liabilities
72,759 
96,557 
Fair Value of Derivative Financial Instruments
2,133 
10,076 
Total Current and Accrued Liabilities
276,341 
446,140 
Deferred Credits
 
 
Deferred Income Taxes
807,955 
1,137,962 
Taxes Refundable to Customers
91,452 
89,448 
Unamortized Investment Tax Credit
470 
731 
Cost of Removal Regulatory Liability
191,217 
184,907 
Other Regulatory Liabilities
102,018 
108,617 
Pension and Other Post-Retirement Liabilities
222,756 
202,807 
Asset Retirement Obligations
114,804 
156,805 
Other Deferred Credits
120,856 
128,073 
Total Deferred Credits
1,651,528 
2,009,350 
Commitments and Contingencies (Note 6)
Total Capitalization and Liabilities
$ 5,541,197 
$ 6,564,939 
Consolidated Balance Sheets (Parenthetical) (USD $)
In Thousands, except Share data, unless otherwise specified
Jun. 30, 2016
Sep. 30, 2015
Statement of Financial Position [Abstract]
 
 
Receivables, Allowance for Uncollectible Accounts
$ 27,413 
$ 29,029 
Common Stock, Par Value
$ 1 
$ 1 
Common Stock, Shares Authorized
200,000,000 
200,000,000 
Common Stock, Shares Issued
84,948,691 
84,594,383 
Common Stock, Shares Outstanding
84,948,691 
84,594,383 
Consolidated Statements Of Cash Flows (Unaudited) (USD $)
In Thousands, unless otherwise specified
9 Months Ended
Jun. 30, 2016
Jun. 30, 2015
OPERATING ACTIVITIES
 
 
Net Loss Available for Common Stock
$ (328,510)
$ (191,724)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
 
 
Impairment of Oil and Gas Producing Properties
915,552 
709,060 
Depreciation, Depletion and Amortization
193,300 
265,298 
Deferred Income Taxes
(269,248)
(198,116)
Excess Tax Benefits Associated with Stock-Based Compensation Awards
(1,786)
(9,064)
Stock-Based Compensation
3,138 
8,383 
Other
9,685 
7,329 
Change in:
 
 
Hedging Collateral Deposits
8,116 
(8,367)
Receivables and Unbilled Revenue
(7,756)
22,175 
Gas Stored Underground and Materials and Supplies
15,683 
20,259 
Unrecovered Purchased Gas Costs
(933)
Other Current Assets
15,334 
14,367 
Accounts Payable
(53,687)
11,153 
Amounts Payable to Customers
(21,337)
11,097 
Customer Advances
(16,198)
(18,961)
Customer Security Deposits
(396)
2,568 
Other Accruals and Current Liabilities
3,375 
13,794 
Other Assets
3,775 
1,124 
Other Liabilities
(8,152)
52,261 
Net Cash Provided by Operating Activities
459,955 
712,636 
INVESTING ACTIVITIES
 
 
Capital Expenditures
(481,781)
(718,965)
Net Proceeds from Sale of Oil and Gas Producing Properties
115,235 
Other
(11,163)
(1,065)
Net Cash Used in Investing Activities
(377,709)
(720,030)
Financing Activities
 
 
Changes in Notes Payable to Banks and Commercial Paper
(85,600)
Excess Tax Benefits Associated with Stock-Based Compensation Awards
1,786 
9,064 
Net Proceeds from Issuance of Long-Term Debt
445,662 
Dividends Paid on Common Stock
(100,419)
(97,330)
Net Proceeds from Issuance of Common Stock
8,358 
8,743 
Net Cash (Used in) Provided by Financing Activities
(90,275)
280,539 
Net Increase (Decrease) in Cash and Temporary Cash Investments
(8,029)
273,145 
Cash and Temporary Cash Investments at October 1
113,596 
36,886 
Cash and Temporary Cash Investments at June 30
105,567 
310,031 
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities:
 
 
Non-Cash Capital Expenditures
44,380 
122,587 
Receivable from Sale of Oil and Gas Producing Properties
$ 22,081 
$ 0 
Summary Of Significant Accounting Policies
Summary Of Significant Accounting Policies
Summary of Significant Accounting Policies
 
Principles of Consolidation.  The Company consolidates all entities in which it has a controlling financial interest.  All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
 
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

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 in the Company's 2015 Form 10-K 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 nine months ended June 30, 2016 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 $6.5 million at June 30, 2016, 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 $130.9 million and $176.3 million at June 30, 2016 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.
 
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 June 30, 2016 as well as March 31, 2016 and December 31, 2015. As such, the Company recognized pre-tax impairment charges of $82.7 million and $915.6 million for the quarter and nine months ended June 30, 2016, respectively. Deferred income tax benefits of $34.8 million and $384.6 million related to the impairment charges were also recognized for the quarter and nine months ended June 30, 2016, respectively. In adjusting estimated future cash flows for hedging under the ceiling test at June 30, 2016, March 31, 2016 and December 31, 2015, estimated future net cash flows were increased by $262.9 million, $252.1 million and $253.7 million, respectively.

On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. The extended joint development agreement gives IOG the option to participate in a 7-well Marcellus pad that is expected to be completed before December 31, 2017, which, if exercised, would increase the maximum number of joint development wells to 82. Under the original joint development agreement, IOG had committed to develop 42 Marcellus wells. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $325 million for its 80% working interest in the 75 joint development wells. As of June 30, 2016, Seneca had received $115.2 million of cash and had recorded a $22.1 million receivable in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the 75 joint development wells. The cash proceeds and receivable were recorded by Seneca as a $137.3 million reduction of property, plant and equipment. 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 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.
Asset Retirement Obligations.  On June 30, 2016, Seneca sold the majority of its Upper Devonian wells in Pennsylvania. While the proceeds from the sale were not significant, it did result in a $58.4 million reduction of its Asset Retirement Obligation at June 30, 2016. The table below is a reconciliation of the asset retirement obligation from September 30, 2015 to June 30, 2016 (in thousands):
 
Nine Months Ended 
 June 30, 2016
 
 
Balance at Beginning of Year
$
156,805

Liabilities Incurred

Revisions of Estimates
17,845

Liabilities Settled
(66,756
)
Accretion Expense
6,910

Balance at June 30, 2016
$
114,804




Accumulated Other Comprehensive Income (Loss).  The components of Accumulated Other Comprehensive Income (Loss) and changes for the quarter and nine months ended June 30, 2016 and 2015, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): 
 
Gains and Losses on Derivative Financial Instruments
Gains and Losses on Securities Available for Sale
Funded Status of the Pension and Other Post-Retirement Benefit Plans
Total
Three Months Ended June 30, 2016
 
 
 
 
Balance at April 1, 2016
$
146,671

$
5,309

$
(69,794
)
$
82,186

Other Comprehensive Gains and Losses Before Reclassifications
(40,842
)
254


(40,588
)
Amounts Reclassified From Other Comprehensive Income (Loss)
(33,859
)


(33,859
)
Balance at June 30, 2016
$
71,970

$
5,563

$
(69,794
)
$
7,739

Nine Months Ended June 30, 2016
 
 
 
 
Balance at October 1, 2015
$
157,197

$
5,969

$
(69,794
)
$
93,372

Other Comprehensive Gains and Losses Before Reclassifications
23,432

(181
)

23,251

Amounts Reclassified From Other Comprehensive Income (Loss)
(108,659
)
(225
)

(108,884
)
Balance at June 30, 2016
$
71,970

$
5,563

$
(69,794
)
$
7,739

Three Months Ended June 30, 2015
 
 
 
 
Balance at April 1, 2015
$
174,413

$
8,296

$
(56,020
)
$
126,689

Other Comprehensive Gains and Losses Before Reclassifications
(5,423
)
57


(5,366
)
Amounts Reclassified From Other Comprehensive Income (Loss)
(29,075
)


(29,075
)
Balance at June 30, 2015
$
139,915

$
8,353

$
(56,020
)
$
92,248

Nine Months Ended June 30, 2015
 
 
 
 
Balance at October 1, 2014
$
43,659

$
8,382

$
(56,020
)
$
(3,979
)
Other Comprehensive Gains and Losses Before Reclassifications
170,719

(29
)

170,690

Amounts Reclassified From Other Comprehensive Income (Loss)
(74,463
)


(74,463
)
Balance at June 30, 2015
$
139,915

$
8,353

$
(56,020
)
$
92,248

 
 
 
 
 

Reclassifications Out of Accumulated Other Comprehensive Income (Loss).  The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the quarter and nine months ended June 30, 2016 and 2015 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 June 30,
Nine Months Ended June 30,
 
 
2016
2015
2016
2015
 
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
 
 
 
 
     Commodity Contracts

$58,354


$50,878


$172,596


$124,386

Operating Revenues
     Commodity Contracts
70

(3
)
4,520

4,884

Purchased Gas
     Foreign Currency Contracts
(51
)

(337
)

Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale


388


Other Income
 
58,373

50,875

177,167

129,270

Total Before Income Tax
 
(24,514
)
(21,800
)
(68,283
)
(54,807
)
Income Tax Expense
 

$33,859


$29,075


$108,884


$74,463

Net of Tax

Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):
                            
At June 30, 2016
 
At September 30, 2015
 
 
 
 
Prepayments
$
11,963

 
$
10,743

Prepaid Property and Other Taxes
10,574

 
13,709

Federal Income Taxes Receivable
5,830

 

State Income Taxes Receivable
2,237

 

Fair Values of Firm Commitments
3,227

 
15,775

Regulatory Assets
13,287

 
20,438

 
$
47,118

 
$
60,665


 
Other Accruals and Current Liabilities.  The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):
                            
At June 30, 2016
 
At September 30, 2015
 
 
 
 
Accrued Capital Expenditures
$
19,287

 
$
53,652

Regulatory Liabilities
22,138

 
5,346

Reserve for Gas Replacement
6,490

 

Federal Income Taxes Payable

 
5,686

State Income Taxes Payable

 
1,170

Other
24,844

 
30,703

 
$
72,759

 
$
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 nine months ended June 30, 2016, the aforementioned securities, amounting to 414,092 shares, were not recognized in the diluted earnings per share calculation for the nine months ended June 30, 2016. For the quarter ended June 30, 2016 and for the quarter and nine months ended June 30, 2015, 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 346,090 shares excluded as being antidilutive for the quarter ended June 30, 2016. There were 180,065 and 2,948 shares excluded as being antidilutive for the quarter and nine months ended June 30, 2015, respectively.
 
Stock-Based Compensation.  The Company granted 309,996 performance shares during the nine months ended June 30, 2016. The weighted average fair value of such performance shares was $30.71 per share for the nine months ended June 30, 2016. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied.  Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.
 
Half of the performance shares granted during the nine months ended June 30, 2016 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 nine months ended June 30, 2016 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 nine months ended June 30, 2016.  The weighted average fair value of such non-performance based restricted stock units was $35.57 per share for the nine months ended June 30, 2016. 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 nine months ended June 30, 2016.

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.

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.

In February 2016, the FASB issued authoritative guidance requiring organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whether they are considered to be capital leases or operating leases. The FASB’s previous authoritative guidance required organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases while excluding operating leases from balance sheet recognition. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. Among other things, the revised guidance specifies that the difference between the compensation recognized for financial reporting purposes and the deduction allowed for tax purposes (excess tax benefit or deficiency) shall be recognized as income tax expense or benefit in the income statement, as opposed to the current treatment where this difference is recognized as additional paid-in capital in the balance sheet. For statement of cash flows purposes, the revised guidance specifies that the excess tax benefit shall be classified along with other income tax cash flows as an item impacting cash flow from operating activities. The current guidance separates the excess tax benefit from other income tax cash flows and classifies the excess tax benefit as an item impacting cash flow from financing activities. The new 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.
Fair Value Measurements
Fair Value Measurements
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 June 30, 2016 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 June 30, 2016
(Thousands of Dollars)   
Level 1
 
Level 2
 
Level 3
 
Netting Adjustments(1)
 
Total(1)
Assets:
 

 
 

 
 

 
 

 
 

Cash Equivalents – Money Market Mutual Funds
$
81,255

 
$

 
$

 
$

 
$
81,255

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
2,991

 

 

 
(2,957
)
 
34

Over the Counter Swaps – Gas and Oil

 
137,774

 

 
(8,990
)
 
128,784

Foreign Currency Contacts

 

 

 
(2,222
)
 
(2,222
)
Other Investments:
 

 
 

 
 

 
 

 
 

Balanced Equity Mutual Fund
36,964

 

 

 

 
36,964

Fixed Income Mutual Fund
31,279

 

 

 

 
31,279

Common Stock – Financial Services Industry
3,813

 

 

 

 
3,813

Hedging Collateral Deposits
3,008

 

 

 

 
3,008

Total                                           
$
159,310

 
$
137,774

 
$

 
$
(14,169
)
 
$
282,915

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Derivative Financial Instruments:
 

 
 

 
 

 
 

 
 

Commodity Futures Contracts – Gas
$
2,957

 
$

 
$

 
$
(2,957
)
 
$

Over the Counter Swaps – Gas and Oil

 
10,694

 

 
(8,990
)
 
1,704

Foreign Currency Contracts

 
2,222

 

 
(2,222
)
 

Total
$
2,957

 
$
12,916

 
$

 
$
(14,169
)
 
$
1,704

Total Net Assets/(Liabilities)
$
156,353

 
$
124,858

 
$

 
$

 
$
281,211

 
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 June 30, 2016 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 $3.0 million at June 30, 2016 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 June 30, 2016 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 June 30, 2016, 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.
 
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 quarter ended June 30, 2015 and the nine months ended June 30, 2016 and 2015, respectively. For the quarters and nine months ended June 30, 2016 and June 30, 2015, 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
June 30, 2016
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 nine months ended June 30, 2016
(2) 
Derivative Financial Instruments are shown on a net basis.        

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)   
 
Total Gains/Losses 
 
 
 
April 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
June 30, 2015
Derivative Financial Instruments(2)
$
4,826

$
(2,249
)
(1) 
$
(106
)
$

$
2,471


(1) 
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended June 30, 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
June 30, 2015
Derivative Financial Instruments(2)
$
1,368

$
(9,053
)
(1) 
$
10,156

$

$
2,471

 
 
 
 
 
 
 

(1) 
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2015
(2) 
Derivative Financial Instruments are shown on a net basis.
Financial Instruments
Financial Instruments
Financial Instruments
 
Long-Term Debt.  The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt.  Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands): 
 
June 30, 2016
 
September 30, 2015
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-Term Debt
$
2,085,686

 
$
2,207,673

 
$
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.
 
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 $39.3 million at June 30, 2016 and $45.3 million at September 30, 2015. The fair value of the equity mutual fund was $37.0 million at June 30, 2016 and $34.9 million at September 30, 2015. The gross unrealized gain on this equity mutual fund was $6.6 million at June 30, 2016 and $6.5 million at September 30, 2015. The fair value of the fixed income mutual fund was $31.3 million at June 30, 2016 and $8.0 million at September 30, 2015. The gross unrealized gain on this fixed income mutual fund was $0.1 million at June 30, 2016. The fair value of the stock of an insurance company was $3.8 million at June 30, 2016 and $4.3 million at September 30, 2015. The gross unrealized gain on this stock was $2.1 million at June 30, 2016 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 June 30, 2016 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 June 30, 2016, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:
Commodity
Units

 
Natural Gas
178.0

 Bcf (short positions)
Natural Gas
1.7

 Bcf (long positions)
Crude Oil
1,722,000

 Bbls (short positions)
    
As of June 30, 2016, the Company was hedging a total of $81.5 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).
As of June 30, 2016, the Company had $124.2 million ($72.0 million after tax) of net hedging gains included in the accumulated other comprehensive income balance. It is expected that $93.2 million ($54.0 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 (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments.

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended June 30, 2016 and 2015 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended June 30,
Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended June 30,
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended June 30,
 
2016
2015
 
2016
2015
 
2016
2015
Commodity Contracts
$
(68,914
)
$
(8,845
)
Operating Revenue
$
58,354

$
50,878

Operating Revenue
$
87

$
159

Commodity Contracts
$
(921
)
$
(84
)
Purchased Gas
$
70

$
(3
)
Not Applicable
$

$

Foreign Currency Contracts
$
(528
)
$
(554
)
Operation and Maintenance Expense
$
(51
)
$

Not Applicable
$

$

Total
$
(70,363
)
$
(9,483
)
 
$
58,373

$
50,875

 
$
87

$
159

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 2016 and 2015 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Nine Months Ended June 30,
Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Nine Months Ended June 30,
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Nine Months Ended June 30,
 
2016
2015
 
2016
2015
 
2016
2015
Commodity Contracts
$
27,304

$
291,749

Operating Revenue
$
172,596

$
124,386

Operating Revenue
$
255

$
3,088

Commodity Contracts
$
1,078

$
4,316

Purchased Gas
$
4,520

$
4,884

Not Applicable
$

$

Foreign Currency Contracts
$
395

$
(554
)
Operation and Maintenance Expense
$
(337
)
$

Not Applicable
$

$

Total
$
28,777

$
295,511

 
$
176,779

$
129,270

 
$
255

$
3,088

 
 
 
 
 
 
 
 
 

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 June 30, 2016, the Company’s Energy Marketing segment had fair value hedges covering approximately 13.3 Bcf (12.7 Bcf of fixed price sales commitments, 0.1 Bcf of fixed price purchase commitments and 0.5 Bcf of commitments related to the withdrawal of storage gas). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.

Derivatives in Fair Value Hedging Relationships
Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the
Nine Months Ended June 30, 2016
(In Thousands)
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the
Nine Months Ended June 30, 2016
(In Thousands)
Commodity Contracts
Operating Revenues
$
13,628

$
(13,628
)
Commodity Contracts
Purchased Gas
$
(512
)
$
512

 
 
$
13,116

$
(13,116
)
 
Credit Risk
 
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions and applicable foreign currency forward contracts with seventeen counterparties of which fourteen are in a net gain position.   On average, the Company had $9.0 million of credit exposure per counterparty in a gain position at June 30, 2016. The maximum credit exposure per counterparty in a gain position at June 30, 2016 was $25.8 million. As of June 30, 2016, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.
 
As of June 30, 2016, thirteen of the seventeen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required.  At June 30, 2016, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $81.6 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 June 30, 2016.    
 
For its exchange traded futures contracts, the Company was required to post $3.0 million in hedging collateral deposits as of June 30, 2016.   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.
Income Taxes
Income Taxes
Income Taxes
 
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands): 
                                                         
Nine Months Ended 
 June 30,
                                                         
2016
 
2015
Current Income Taxes 
 

 
 

Federal                                              
$
(686
)
 
$
27,311

State                                                  
18,293

 
14,195

 
 
 
 
Deferred Income Taxes                                
 

 
 

Federal                                               
(184,419
)
 
(134,369
)
State                                                    
(84,829
)
 
(63,747
)
 
(251,641
)
 
(156,610
)
Deferred Investment Tax Credit                            
(261
)
 
(311
)
 
 
 
 
Total Income Taxes                                      
$
(251,902
)
 
$
(156,921
)
Presented as Follows:
 

 
 

Other Income
(261
)
 
(311
)
Income Tax Expense (Benefit)
(251,641
)
 
(156,610
)
 
 
 
 
Total Income Taxes
$
(251,902
)
 
$
(156,921
)


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): 
 
Nine Months Ended 
 June 30,
 
2016
 
2015
U.S. Income (Loss) Before Income Taxes
$
(580,412
)
 
$
(348,645
)
 
 

 
 

Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%
$
(203,144
)
 
$
(122,026
)
State Income Taxes (Benefit)
(43,248
)
 
(32,209
)
Miscellaneous
(5,510
)
 
(2,686
)
 
 
 
 
Total Income Taxes
$
(251,902
)
 
$
(156,921
)

 
As a result of a settlement reached during the quarter ended June 30, 2016, the Company has reduced the balance of unrecognized tax benefits by $3.1 million, of which $0.8 million was recorded as an income tax benefit. As of June 30, 2016, the entire balance of unrecognized tax benefits would favorably impact the effective tax rate, if recognized.
Capitalization
Capitalization
Capitalization
 
Common Stock.  During the nine months ended June 30, 2016, the Company issued 172,574 original issue shares of common stock as a result of stock option and SARs exercises and 67,733 original issue shares of common stock for restricted stock units that vested.  In addition, the Company issued 102,139 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 92,756 original issue shares of common stock for the Company’s 401(k) plans.  The Company also issued 13,384 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the nine months ended June 30, 2016.  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 nine months ended June 30, 2016, 59,278 shares of common stock were tendered to the Company for such purposes.  The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. There were also 35,000 restricted stock award shares forfeited during the nine months ended June 30, 2016.
 
Current Portion of Long-Term Debt.    None of the Company’s long-term debt at June 30, 2016 will mature within the following twelve-month period.
Commitments And Contingencies
Commitments And Contingencies
Commitments and Contingencies
 
Environmental Matters.  The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment.  The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements.  It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. 
    
At June 30, 2016, 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 $4.0 million.  The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 11 years.

The Company's estimated liability for clean-up costs discussed above includes a $2.9 million estimated liability related to the remediation of 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 has also been completed. Restoration work is substantially complete. 
 
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.
Business Segment Information
Business Segment Information
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 June 30, 2016 and September 30, 2015 is shown in the tables below.  
Quarter Ended June 30, 2016 (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
$156,835
$52,998
$65
$106,568
$17,408
$333,874
$1,508
$235
$335,617
Intersegment Revenues
$—
$22,795
$25,417
$1,729
$231
$50,172
$—
$(50,172)
$—
Segment Profit: Net Income (Loss)
$(19,165)
$17,323
$9,473
$2,179
$(590)
$9,220
$430
$(1,364)
$8,286

 


 





Nine Months Ended June 30, 2016 (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
$452,583
$162,627
$303
$463,154
$77,827
$1,156,494
$2,775
$674
$1,159,943
Intersegment Revenues
$—
$68,272
$65,601
$10,757
$855
$145,485
$—
$(145,485)
$—
Segment Profit: Net Income (Loss)
$(469,586)
$59,794
$21,962
$52,745
$4,117
$(330,968)
$595
$1,863
$(328,510)
 
 
 
 
 
 
 
 
 
 
(Thousands)
Exploration and Production
Pipeline and Storage
Gathering
Utility
Energy Marketing
Total Reportable Segments
All Other
Corporate and Intersegment Eliminations
Total Consolidated
Segment Assets:
 
 
 
 
 
 
 
 
 
At June 30, 2016
$1,436,632
$1,627,756
$520,440
$1,904,880
$65,305
$5,555,013
$76,846
$(90,662)
$5,541,197
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 June 30, 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
$159,404
$47,012
$126
$110,002
$22,420
$338,964
$634
$217
$339,815
Intersegment Revenues
$—
$21,833
$16,748
$2,614
$379
$41,574
$—
$(41,574)
$—
Segment Profit: Net Income (Loss)
$(323,113)
$17,714
$6,226
$5,727
$1,533
$(291,913)
$(28)
$(1,193)
$(293,134)
Nine Months Ended June 30, 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
$529,590
$154,515
$361
$630,049
$142,753
$1,457,268
$1,906
$677
$1,459,851
Intersegment Revenues
$—
$66,347
$58,541
$13,670
$796
$139,354
$—
$(139,354)
$—
Segment Profit: Net Income (Loss)
$(349,955)
$61,868
$24,254
$66,558
$7,732
$(189,543)
$66
$(2,247)
$(191,724)
 
 
 
 
 
 
 
 
 
 
Retirement Plan And Other Post-Retirement Benefits
Retirement Plan and Other Post-Retirement Benefits
Retirement Plan and Other Post-Retirement Benefits
 
Components of Net Periodic Benefit Cost (in thousands):
 
 
Retirement Plan
 
Other Post-Retirement Benefits
Three Months Ended June 30,
2016
2015
 
2016
2015





 




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)
14

88

 
3,936

4,739






 




Net Periodic Benefit Cost
$
7,049

$
7,578

 
$
2,886

$
2,270

 
 
 
 
 
 
 
Retirement Plan
 
Other Post-Retirement Benefits
Nine Months Ended June 30,
2016
2015
 
2016
2015
 
 
 
 
 
 
Service Cost
$
8,783

$
9,036

 
$
1,748

$
2,019

Interest Cost
31,736

30,913

 
15,289

14,464

Expected Return on Plan Assets
(44,527
)
(44,712
)
 
(23,651
)
(25,566
)
Amortization of Prior Service Cost (Credit)
925

137

 
(684
)
(1,435
)
Amortization of Losses
24,186

27,097

 
4,147

3,111

Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)
7,531

8,434

 
14,657

17,055

 
 
 
 
 
 
Net Periodic Benefit Cost
$
28,634

$
30,905

 
$
11,506

$
9,648

 
 
 
 
 
 
(1) 
The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.
 
Employer Contributions.    During the nine months ended June 30, 2016, the Company contributed $4.0 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.3 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits.  In the remainder of 2016, the Company expects to make no additional contributions to the Retirement Plan. In the remainder of 2016, the Company expects to contribute approximately $0.3 million to its VEBA trusts and 401(h) accounts.
Regulatory Matters
Regulatory Matters
Regulatory Matters
    
On April 28, 2016, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million. Distribution Corporation explained in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense that are not reflected in current rates, among other things. The rate filing includes a proposal for system infrastructure modernization that includes the acceleration of Distribution Corporation’s replacement of certain gas mains, which are of a type generically classified by the NYPSC as “leak prone pipe”. The NYPSC may accept, reject or modify the Company’s filing. In June of 2016, the administrative law judge assigned to the case adopted a schedule that requires Staff and intervenor testimony to be filed by August 26, 2016, and establishes the commencement of an evidentiary hearing on October 5, 2016. Assuming standard procedure, new rates, if accepted, would become effective on or about April 1, 2017. The outcome of the proceeding cannot be ascertained at this time.
FERC Rate Proceedings
Supply Corporation's current rate 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.
By order dated January 21, 2016, the FERC began a NGA Section 5 rate review of Empire's rates. As required by that order, Empire filed a Cost and Revenue Study on April 5, 2016. On May 25, 2016, Empire reached a settlement in principle on this matter that would, among other things, reduce certain of Empire’s maximum transportation rates over a 14-month period, which, based on current contracts, is estimated to reduce Empire’s revenues on a yearly basis by between $3 million to $4 million. The settlement also reduces Empire’s depreciation rate from 2.5% to 2%. In addition, the settlement provides an annual revenue sharing mechanism, pursuant to which non-expansion transportation revenues exceeding $73.5 million are shared on a tiered basis. Under the settlement, Empire will be required to make a general rate filing no later than July 1, 2021. On July 22, 2016, Empire filed the settlement at the FERC and is awaiting approval. The settlement is not expected to have a material impact on the Company’s financial condition.
Summary Of Significant Accounting Policies (Policy)
Principles of Consolidation.  The Company consolidates all entities in which it has a controlling financial interest.  All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
 
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.
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 in the Company's 2015 Form 10-K 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 nine months ended June 30, 2016 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 $6.5 million at June 30, 2016, 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 $130.9 million and $176.3 million at June 30, 2016 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.
 
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 June 30, 2016 as well as March 31, 2016 and December 31, 2015. As such, the Company recognized pre-tax impairment charges of $82.7 million and $915.6 million for the quarter and nine months ended June 30, 2016, respectively. Deferred income tax benefits of $34.8 million and $384.6 million related to the impairment charges were also recognized for the quarter and nine months ended June 30, 2016, respectively. In adjusting estimated future cash flows for hedging under the ceiling test at June 30, 2016, March 31, 2016 and December 31, 2015, estimated future net cash flows were increased by $262.9 million, $252.1 million and $253.7 million, respectively.

On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. The extended joint development agreement gives IOG the option to participate in a 7-well Marcellus pad that is expected to be completed before December 31, 2017, which, if exercised, would increase the maximum number of joint development wells to 82. Under the original joint development agreement, IOG had committed to develop 42 Marcellus wells. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $325 million for its 80% working interest in the 75 joint development wells. As of June 30, 2016, Seneca had received $115.2 million of cash and had recorded a $22.1 million receivable in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the 75 joint development wells. The cash proceeds and receivable were recorded by Seneca as a $137.3 million reduction of property, plant and equipment. 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 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.
Asset Retirement Obligations.  On June 30, 2016, Seneca sold the majority of its Upper Devonian wells in Pennsylvania. While the proceeds from the sale were not significant, it did result in a $58.4 million reduction of its Asset Retirement Obligation at June 30, 2016. The table below is a reconciliation of the asset retirement obligation from September 30, 2015 to June 30, 2016 (in thousands):
 
Nine Months Ended 
 June 30, 2016
 
 
Balance at Beginning of Year
$
156,805

Liabilities Incurred

Revisions of Estimates
17,845

Liabilities Settled
(66,756
)
Accretion Expense
6,910

Balance at June 30, 2016
$
114,804

Accumulated Other Comprehensive Income (Loss).  The components of Accumulated Other Comprehensive Income (Loss) and changes for the quarter and nine months ended June 30, 2016 and 2015, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): 
 
Gains and Losses on Derivative Financial Instruments
Gains and Losses on Securities Available for Sale
Funded Status of the Pension and Other Post-Retirement Benefit Plans
Total
Three Months Ended June 30, 2016
 
 
 
 
Balance at April 1, 2016
$
146,671

$
5,309

$
(69,794
)
$
82,186

Other Comprehensive Gains and Losses Before Reclassifications
(40,842
)
254


(40,588
)
Amounts Reclassified From Other Comprehensive Income (Loss)
(33,859
)


(33,859
)
Balance at June 30, 2016
$
71,970

$
5,563

$
(69,794
)
$
7,739

Nine Months Ended June 30, 2016
 
 
 
 
Balance at October 1, 2015
$
157,197

$
5,969

$
(69,794
)
$
93,372

Other Comprehensive Gains and Losses Before Reclassifications
23,432

(181
)

23,251

Amounts Reclassified From Other Comprehensive Income (Loss)
(108,659
)
(225
)

(108,884
)
Balance at June 30, 2016
$
71,970

$
5,563

$
(69,794
)
$
7,739

Three Months Ended June 30, 2015
 
 
 
 
Balance at April 1, 2015
$
174,413

$
8,296

$
(56,020
)
$
126,689

Other Comprehensive Gains and Losses Before Reclassifications
(5,423
)
57


(5,366
)
Amounts Reclassified From Other Comprehensive Income (Loss)
(29,075
)


(29,075
)
Balance at June 30, 2015
$
139,915

$
8,353

$
(56,020
)
$
92,248

Nine Months Ended June 30, 2015
 
 
 
 
Balance at October 1, 2014
$
43,659

$
8,382

$
(56,020
)
$
(3,979
)
Other Comprehensive Gains and Losses Before Reclassifications
170,719

(29
)

170,690

Amounts Reclassified From Other Comprehensive Income (Loss)
(74,463
)


(74,463
)
Balance at June 30, 2015
$
139,915

$
8,353

$
(56,020
)
$
92,248

 
 
 
 
 

Reclassifications Out of Accumulated Other Comprehensive Income (Loss).  The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the quarter and nine months ended June 30, 2016 and 2015 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 June 30,
Nine Months Ended June 30,
 
 
2016
2015
2016
2015
 
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
 
 
 
 
     Commodity Contracts

$58,354


$50,878


$172,596


$124,386

Operating Revenues
     Commodity Contracts
70

(3
)
4,520

4,884

Purchased Gas
     Foreign Currency Contracts
(51
)

(337
)

Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale


388


Other Income
 
58,373

50,875

177,167

129,270

Total Before Income Tax
 
(24,514
)
(21,800
)
(68,283
)
(54,807
)
Income Tax Expense