Table of Contents


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________________________________ 
FORM 10-Q
__________________________________________________________ 
(Mark One)
ýQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31,June 30, 2016
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: 1-12074
__________________________________________________________ 
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Delaware72-1235413
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
 
625 E. Kaliste Saloom Road 
Lafayette, Louisiana70508
(Address of principal executive offices)(Zip Code)
(337) 237-0410
(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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    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  ý    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.
Large accelerated filerýAccelerated 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  ý
As of May 4,August 2, 2016, there were 56,864,6075,689,930 shares of the registrant’s common stock, par value $.01 per share, outstanding.
 

TABLE OF CONTENTS
 
  Page
 
Item 1. 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
Item 1.
Item 1A.
Item 2.
Item 6.
 
 

PART I – FINANCIAL INFORMATION
 
Item 1. Financial Statements
 
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET
(In thousands of dollars)
March 31,
2016
 December 31,
2015
June 30,
2016
 December 31,
2015
(Unaudited) (Note 1)(Unaudited) (Note 1)
Assets      
Current assets:      
Cash and cash equivalents$367,134
 $10,759
$169,194
 $10,759
Accounts receivable42,185
 48,031
38,276
 48,031
Fair value of derivative contracts30,222
 38,576
11,887
 38,576
Current income tax receivable46,174
 46,174
46,174
 46,174
Inventory535
 535
Other current assets6,531
 6,346
12,080
 6,881
Total current assets492,781
 150,421
277,611
 150,421
Oil and gas properties, full cost method of accounting:      
Proved9,481,859
 9,375,898
9,518,245
 9,375,898
Less: accumulated depreciation, depletion and amortization(8,796,412) (8,603,955)(8,960,440) (8,603,955)
Net proved oil and gas properties685,447
 771,943
557,805
 771,943
Unevaluated421,429
 440,043
425,204
 440,043
Other property and equipment, net28,667
 29,289
27,968
 29,289
Other assets, net18,257
 18,473
28,183
 18,473
Total assets$1,646,581
 $1,410,169
$1,316,771
 $1,410,169
Liabilities and Stockholders’ Equity      
Current liabilities:      
Accounts payable to vendors$38,200
 $82,207
$28,914
 $82,207
Undistributed oil and gas proceeds3,875
 5,992
5,071
 5,992
Accrued interest22,901
 9,022
9,773
 9,022
Fair value of derivative contracts37
 
Asset retirement obligations23,465
 21,291
33,695
 21,291
Current portion of long-term debt459,201
 
288,336
 
Other current liabilities32,671
 40,712
34,793
 40,712
Total current liabilities580,313
 159,224
400,619
 159,224
Long-term debt1,063,090
 1,060,955
1,122,901
 1,060,955
Asset retirement obligations209,848
 204,575
203,661
 204,575
Other long-term liabilities18,329
 25,204
18,446
 25,204
Total liabilities1,871,580
 1,449,958
1,745,627
 1,449,958
Commitments and contingencies
 

 
Stockholders’ equity:      
Common stock, $.01 par value; authorized 150,000,000 shares; issued 55,806,817 and 55,302,325 shares, respectively558
 553
Treasury stock (16,582 shares, at cost)(860) (860)
Common stock, $.01 par value; authorized 30,000,000 shares; issued 5,592,641 and 5,530,232 shares, respectively56
 55
Treasury stock (1,658 shares, at cost)(860) (860)
Additional paid-in capital1,650,969
 1,648,189
1,654,731
 1,648,687
Accumulated deficit(1,894,407) (1,705,623)(2,090,168) (1,705,623)
Accumulated other comprehensive income18,741
 17,952
7,385
 17,952
Total stockholders’ equity(224,999) (39,789)(428,856) (39,789)
Total liabilities and stockholders’ equity$1,646,581
 $1,410,169
$1,316,771
 $1,410,169

 The accompanying notes are an integral part of this balance sheet.


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STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
Three Months Ended
March 31,
 Three Months Ended
June 30,
 Six Months Ended
June 30,
2016 2015 2016 2015 2016 2015
Operating revenue:           
Oil production$60,275
 $107,507
 $72,711
 $111,585
 $132,986
 $219,092
Natural gas production15,173
 28,337
 12,553
 26,907
 27,726
 55,244
Natural gas liquids production4,735
 12,366
 3,718
 11,033
 8,453
 23,399
Other operational income356
 2,160
 337
 
 693
 1,792
Derivative income, net138
 3,128
 
 
 
 2,427
Total operating revenue80,677
 153,498
 89,319
 149,525
 169,858
 301,954
Operating expenses:           
Lease operating expenses19,547
 27,577
 18,826
 27,429
 38,373
 55,006
Transportation, processing and gathering expenses841
 17,703
 7,183
 19,940
 8,024
 37,643
Production taxes481
 2,515
 578
 1,827
 1,059
 4,342
Depreciation, depletion and amortization61,558
 86,422
 46,231
 77,951
 107,789
 164,373
Write-down of oil and gas properties129,204
 491,412
 118,649
 224,294
 247,853
 715,706
Accretion expense9,983
 6,409
 10,082
 6,408
 20,065
 12,817
Salaries, general and administrative expenses13,707
 17,007
 20,014
 16,418
 32,768
 33,425
Incentive compensation expense4,979
 1,563
 4,670
 1,264
 9,649
 2,827
Restructuring fees9,436
 
 10,389
 
Other operational expenses12,527
 84
 27,680
 1,454
 40,207
 1,170
Derivative expense, net626
 701
 488
 
Total operating expenses252,827
 650,692
 263,975
 377,686
 516,664
 1,027,309
Loss from operations(172,150) (497,194) (174,656) (228,161) (346,806) (725,355)
Other (income) expenses:           
Interest expense15,241
 10,365
 17,599
 10,472
 32,840
 20,837
Interest income(114) (122) (302) (66) (416) (188)
Other income(298) (143) (270) (613) (568) (756)
Other expense2
 
 9
 
 11
 
Total other expenses14,831
 10,100
 17,036
 9,793
 31,867
 19,893
Loss before income taxes(186,981) (507,294) (191,692) (237,954) (378,673) (745,248)
Provision (benefit) for income taxes:           
Current(1,074) 
 (2,113) 
 (3,187) 
Deferred2,877
 (179,906) 6,182
 (85,048) 9,059
 (264,954)
Total income taxes1,803
 (179,906) 4,069
 (85,048) 5,872
 (264,954)
Net loss$(188,784) $(327,388) $(195,761) $(152,906) $(384,545) $(480,294)
Basic loss per share$(3.39) $(5.93) $(35.05) $(27.68) $(68.94) $(86.99)
Diluted loss per share$(3.39) $(5.93) $(35.05) $(27.68) $(68.94) $(86.99)
Average shares outstanding55,713
 55,181
 5,585
 5,525
 5,578
 5,521
Average shares outstanding assuming dilution55,713
 55,181
 5,585
 5,525
 5,578
 5,521
 
The accompanying notes are an integral part of this statement.


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STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
(Unaudited)
Three Months Ended
March 31,
 Three Months Ended
June 30,
 Six Months Ended
June 30,
2016 2015 2016 2015 2016 2015
Net loss$(188,784) $(327,388) $(195,761) $(152,906) $(384,545) $(480,294)
Other comprehensive loss, net of tax effect:    
Other comprehensive income (loss), net of tax effect:       
Derivatives(5,285) (8,858) (11,356) (31,480) (16,640) (40,338)
Foreign currency translation6,074
 (3,645) 
 1,324
 6,073
 (2,321)
Comprehensive loss$(187,995) $(339,891) $(207,117) $(183,062) $(395,112) $(522,953)
 
The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)
Three Months Ended
March 31,
Six Months Ended
June 30,
2016 20152016 2015
Cash flows from operating activities:      
Net loss$(188,784) $(327,388)$(384,545) $(480,294)
Adjustments to reconcile net loss to net cash provided by operating activities:      
Depreciation, depletion and amortization61,558
 86,422
107,789
 164,373
Write-down of oil and gas properties129,204
 491,412
247,853
 715,706
Accretion expense9,983
 6,409
20,065
 12,817
Deferred income tax provision (benefit)2,877
 (179,906)9,059
 (264,954)
Settlement of asset retirement obligations(4,667) (17,145)(10,706) (35,923)
Non-cash stock compensation expense2,312
 2,640
4,682
 6,028
Non-cash derivative expense192
 1,511
1,025
 7,931
Non-cash interest expense4,635
 4,318
9,403
 8,737
Other non-cash expense6,081
 
6,081
 
Change in current income taxes(1,074) 7,188
(3,187) 7,206
Decrease in accounts receivable5,845
 8,206
9,755
 23,047
(Increase) decrease in other current assets(185) 1,883
Increase in other current assets(5,283) (1,959)
Decrease in accounts payable(2,138) (8,657)(321) (7,826)
Increase in other current liabilities3,898
 6,889
Decrease in other current liabilities(5,920) (8,720)
Other(298) (260)(7,880) (504)
Net cash provided by operating activities29,439
 83,522
Net cash (used in) provided by operating activities(2,130) 145,665
Cash flows from investing activities:      
Investment in oil and gas properties(129,859) (169,895)(179,311) (264,355)
Proceeds from sale of oil and gas properties, net of expenses
 10,100
Investment in fixed and other assets(496) (662)(898) (727)
Change in restricted funds1,045
 177,642
1,045
 179,475
Net cash (used in) provided by investing activities(129,310) 7,085
Net cash used in investing activities(179,164) (75,507)
Cash flows from financing activities:      
Proceeds from bank borrowings477,000
 5,000
477,000
 5,000
Repayments of bank borrowings(20,000) (5,000)(135,500) (5,000)
Repayments of building loan(95) 
(189) 
Deferred financing costs(900) 
Net payments for share-based compensation(650) (2,991)(673) (3,069)
Net cash provided by (used in) financing activities456,255
 (2,991)339,738
 (3,069)
Effect of exchange rate changes on cash(9) 24
(9) 78
Net change in cash and cash equivalents356,375
 87,640
158,435
 67,167
Cash and cash equivalents, beginning of period10,759
 74,488
10,759
 74,488
Cash and cash equivalents, end of period$367,134
 $162,128
$169,194
 $141,655
 
The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
Note 1 – Interim Financial Statements
 
The condensed consolidated financial statements of Stone Energy Corporation (“Stone” or the "Company") and its subsidiaries as of March 31,June 30, 2016 and for the three and six month periods ended March 31,June 30, 2016 and 2015 are unaudited and reflect all adjustments (consisting only of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim periods. The condensed consolidated balance sheet as of December 31, 2015 has been derived from the audited financial statements as of that date contained in our Annual Report on Form 10-K for the year ended December 31, 2015 (our “2015 Annual Report on Form 10-K”). The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations, contained in our 2015 Annual Report on Form 10-K. The results of operations for the three and six month periodperiods ended March 31,June 30, 2016 are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation.

On May 27, 2016, the board of directors of the Company approved a 1-for-10 reverse stock split of the Company's issued and outstanding shares of common stock. The reverse stock split was effective upon the filing and effectiveness of a certificate of amendment to the Company's certificate of incorporation after the market closed on June 10, 2016, and the common stock began trading on a split-adjusted basis when the market opened on June 13, 2016. The effect of the reverse stock split was to combine each 10 shares of outstanding common stock prior to the reverse split into one new share subsequent to the reverse split. The Company's authorized shares of common stock were proportionately decreased in connection with the reverse stock split. Additionally, the overall and per share limitations in the Company’s 2009 Amended and Restated Stock Incentive Plan, as amended from time to time, and outstanding awards thereunder were also proportionately adjusted. The Company retained the current par value of $.01 per share for all shares of common stock.

All references in the financial statements and notes thereto to number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the 1-for-10 reverse stock split. Stockholders' equity reflects the reverse stock split by reclassifying from common stock to additional paid-in capital an amount equal to the par value of the reduction in the number of shares as a result of the reverse split.
 
Note 2 – Going Concern
 
The accompanying condensed consolidated financial statements have been prepared assuming the companyCompany will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these condensed consolidated financial statements. As such, the accompanying condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the companyCompany be unable to continue as a going concern.

The level of our indebtedness of $1,544$1,428 million as of June 30, 2016 and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. At March 31, 2016, we were in compliance with all of our financial covenants under our bank credit facility andindebtedness, particularly the indentures governing our outstanding notes. However, given the lower commodity prices and our reduced hedged position in 2016, we anticipate that we will exceed themaximum Consolidated Funded Debt to consolidated EBITDA (“Consolidated Funded Leverage”) financial covenant of 3.75 to 1 set forth in our bank credit agreement atagreement. If we exceed the end of the second quarter of 2016, whichmaximum Consolidated Funded Leverage financial covenant, we would require usbe required to seek a waiver or amendment from our bank lenders. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.

On June 14, 2016, we entered into an amendment to the bank credit facility (see Note 5 – Debt) which, among other things, requires that we maintain minimum liquidity of $125.0 million through January 15, 2017 and revised the maximum Consolidated Funded Leverage financial covenant from 3.75 to 1 to 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ending September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter. We were in compliance with all covenants under the bank credit facility as of June 30, 2016, however, the minimum liquidity requirement and other restrictions under the credit facility may prevent us from being able to meet our interest payment obligation on the 7½% Senior Notes due in 2022 (the “2022 Notes”) in the fourth quarter of 2016 as well as the subsequent maturity of our 1¾% Senior Convertible Notes due in March 2017 (the “2017 Convertible Notes”). Additionally, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017 unless a material portion of our debt is repaid, reduced or exchanged into equity. These conditions raise substantial doubt about our ability to continue as a going concern.

Additionally, on April 13, 2016, our borrowing base under our bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million
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Table of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. We have not taken any action or made an election of actions to be taken to cure the borrowing base deficiency.Contents

We arein discussions with our banks regarding an amendment to our bank credit facility to address the potential covenant issue. We cannot provide any assurances that we will reach an agreement with the lenders under our bank credit facility on a waiver or amendment on a timely basis, or on satisfactory terms, to alleviate any non-compliance with our debt covenants. In addition to our borrowings under our bank credit facility, we have $1,075 million of senior indebtedness, including our 1¾% Senior Convertible Notes due in March 2017 (the "2017 Convertible Notes").
We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, asset sales and a prepackaged or prearranged bankruptcy filing. We cannot provide any assurances that we will be able to complete a private restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness.



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Note 3 – Earnings Per Share
 
The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods:
Three Months Ended
March 31,
 Three Months Ended
June 30,
 Six Months Ended
June 30,
2016 2015 2016 2015 2016 2015
(In thousands, except per share data) (In thousands, except per share data)
Income (numerator):           
Basic:           
Net loss$(188,784) $(327,388) $(195,761) $(152,906) $(384,545) $(480,294)
Net income attributable to participating securities
 
 
 
 
 
Net loss attributable to common stock - basic$(188,784) $(327,388) $(195,761) $(152,906) $(384,545) $(480,294)
Diluted:           
Net loss$(188,784) $(327,388) $(195,761) $(152,906) $(384,545) $(480,294)
Net income attributable to participating securities
 
 
 
 
 
Net loss attributable to common stock - diluted$(188,784) $(327,388) $(195,761) $(152,906) $(384,545) $(480,294)
Weighted average shares (denominator):           
Weighted average shares - basic55,713
 55,181
 5,585
 5,525
 5,578
 5,521
Dilutive effect of stock options
 
 
 
 
 
Dilutive effect of convertible notes
 
 
 
 
 
Weighted average shares - diluted55,713
 55,181
 5,585
 5,525
 5,578
 5,521
Basic loss per share$(3.39) $(5.93) $(35.05) $(27.68) $(68.94) $(86.99)
Diluted loss per share$(3.39) $(5.93) $(35.05) $(27.68) $(68.94) $(86.99)
 
All outstanding stock options were considered antidilutive during the three and six months ended March 31,June 30, 2016 (approximately 129,00012,900 shares) and during the three and six months ended March 31,June 30, 2015 (approximately 204,00017,400 shares) because we had net losses for such periods.
 
During the three months ended March 31,June 30, 2016 and 2015, approximately 504,00012,100 shares and 370,0002,900 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors. During the six months ended June 30, 2016 and 2015, approximately 62,200 shares and 39,900 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors.
 
For the three and six months ended March 31,June 30, 2016 and 2015, the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such periods. For the three and six months ended March 31,June 30, 2016 and 2015, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 5 – Debt) and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in Note 5 – Debt), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.
 
Note 4 – Derivative Instruments and Hedging Activities
 
Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.
 
The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, it is recorded as either an asset or liability measured at fair value and subsequent changes in the

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derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and natural gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value and subsequent changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities.

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We have entered into fixed-price swaps and costless collars with various counterparties for a portion of our expected 2016 oil and natural gas production from the Gulf Coast Basin. Our fixed-price oil swap settlements and oil collar settlements are based on an average of the New York Mercantile Exchange (“NYMEX”) closing price for West Texas Intermediate crude oil during the entire calendar month. Our fixed-price gas swap settlements are based on the NYMEX price for the last day of a respective contract month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, The Bank of Nova Scotia and Natixis. Our oil collar contract is with The Bank of Nova Scotia.

All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an "investment grade" credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At May 4,August 2, 2016, two counterparties accounted for approximately 86% of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility. 
The following tables illustrate our derivative positions for calendar year 2016 as of May 4,August 2, 2016:
 Fixed-Price Swaps (NYMEX)
 Natural Gas Oil
 
Daily Volume
(MMBtus/d)
 
Swap Price
($)
 
Daily Volume
(Bbls/d)
 
Swap Price
($)
201610,000
 4.110
 1,000
 49.75
201610,000
 4.120
 1,000
 52.78
2016

 

 1,000
 90.00
 
 Costless Collar (NYMEX)
 Oil
 
Daily Volume
(Bbls/d)
 Floor Price ($) Ceiling Price ($)
20161,000
 45.00
 54.75
 Collar (NYMEX)
 Oil
 
Daily Volume
(Bbls/d)
 Floor Price ($) Ceiling Price ($)
20161,000
 45.00
 54.75

We previously discontinued hedge accounting for certain 2015 natural gas contracts, as it became no longer probable that our Gulf of Mexico ("GOM") natural gas production would be sufficient to cover the GOM volumes hedged. Additionally, a small portion of our cash flow hedges are typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products are not 100% correlative to changes in the underlying price basis indicative in the derivative contract. At March 31,June 30, 2016, we had accumulated other comprehensive income of $18.7$7.4 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of March 31,June 30, 2016. The $18.7$7.4 million of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.
 
Derivatives qualifying as hedging instruments:
 
The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at March 31,June 30, 2016 and December 31, 2015:2015. We had an immaterial collar contract qualifying as a hedging instrument, with a fair value of approximately $37,000, classified as a current liability in our balance sheet at June 30, 2016.

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Fair Value of Derivatives Qualifying as Hedging Instruments at
March 31, 2016
June 30, 2016June 30, 2016
(In millions)
Asset Derivatives Liability DerivativesAsset Derivatives Liability Derivatives
DescriptionBalance Sheet Location 
Fair
Value
 Balance Sheet Location 
Fair
Value
Balance Sheet Location 
Fair
Value
 Balance Sheet Location 
Fair
Value
Commodity contracts
Current assets: Fair value of
derivative contracts
 $30.2
 
Current liabilities: Fair value
of derivative contracts
 $
Current assets: Fair value of
derivative contracts
 $11.9
 
Current liabilities: Fair value
of derivative contracts
 $
Long-term assets: Fair value
of derivative contracts
 
 
Long-term liabilities: Fair
value of derivative contracts
 
Long-term assets: Fair value
of derivative contracts
 
 
Long-term liabilities: Fair
value of derivative contracts
 
 $30.2
 $
 $11.9
 $
        
Fair Value of Derivatives Qualifying as Hedging Instruments atDecember 31, 2015(In millions)
Asset Derivatives Liability DerivativesAsset Derivatives Liability Derivatives
DescriptionBalance Sheet Location 
Fair
Value
 Balance Sheet Location 
Fair
Value
Balance Sheet Location 
Fair
Value
 Balance Sheet Location 
Fair
Value
Commodity contracts
Current assets: Fair value of
derivative contracts
 $38.6
 
Current liabilities: Fair value
of derivative contracts
 $
Current assets: Fair value of
derivative contracts
 $38.6
 
Current liabilities: Fair value
of derivative contracts
 $
Long-term assets: Fair value
of derivative contracts
 
 
Long-term liabilities: Fair
value of derivative contracts
 
Long-term assets: Fair value
of derivative contracts
 
 
Long-term liabilities: Fair
value of derivative contracts
 
 $38.6
 $
 $38.6
 $
 
The following table disclosestables disclose the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three and six month periods ended March 31,June 30, 2016 and 2015:2015.
Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended March 31, 2016 and 2015
for the Three Months Ended June 30, 2016 and 2015for the Three Months Ended June 30, 2016 and 2015
(In millions)
Derivatives in
Cash Flow Hedging
Relationships
 
Amount of Gain
(Loss) Recognized
in Other
Comprehensive
Income on
Derivatives
 
Gain (Loss) Reclassified from
Accumulated Other Comprehensive
Income into Income
(Effective Portion) (a)
 
Gain (Loss) Recognized in Income
on Derivatives
(Ineffective Portion)
 Amount of Gain
(Loss) Recognized
in Other
Comprehensive
Income on
Derivatives
 Gain (Loss) Reclassified from
Accumulated Other Comprehensive
Income into Income
(Effective Portion) (a)
 Gain (Loss) Recognized in Income
on Derivatives
(Ineffective Portion)
 2016 2015 Location 2016 2015 Location 2016 2015 2016 2015 Location 2016 2015 Location 2016 2015
Commodity contracts $4.6
 $22.9
 
Operating revenue -
oil/natural gas production
 $12.8
 $36.8
 
Derivative income
(expense), net
 $0.1
 $0.9
 $(8.6) $(18.8) 
Operating revenue -
oil/natural gas production
 $8.9
 $30.4
 
Derivative income
(expense), net
 $(0.6) $(0.4)
Total $4.6
 $22.9
 $12.8
 $36.8
 $0.1
 $0.9
 $(8.6) $(18.8) $8.9
 $30.4
 $(0.6) $(0.4)

(a)For the three months ended March 31,June 30, 2016, effective hedging contracts increased oil revenue by $9.3$5.1 million and increased natural gas revenue by $3.5$3.8 million. For the three months ended March 31,June 30, 2015, effective hedging contracts increased oil revenue by $34.0$26.4 million and increased natural gas revenue by $2.8$4.0 million.
Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Six Months Ended June 30, 2016 and 2015
(In millions)
Derivatives in
Cash Flow Hedging
Relationships
 Amount of Gain
(Loss) Recognized
in Other
Comprehensive
Income on
Derivatives
 Gain (Loss) Reclassified from
Accumulated Other Comprehensive
Income into Income
(Effective Portion) (a)
 Gain (Loss) Recognized in Income
on Derivatives
(Ineffective Portion)
  2016 2015 Location 2016 2015 Location 2016 2015
Commodity contracts $(4.0) $4.1
 Operating revenue -
oil/natural gas production
 $21.7
 $67.2
 Derivative income
(expense), net
 $(0.5) $0.5
Total $(4.0) $4.1
   $21.7
 $67.2
   $(0.5) $0.5


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(a)For the six months ended June 30, 2016, effective hedging contracts increased oil revenue by $14.4 million and increased natural gas revenue by $7.3 million. For the six months ended June 30, 2015, effective hedging contracts increased oil revenue by $60.4 million and increased natural gas revenue by $6.8 million.

Derivatives not qualifying as hedging instruments:
  
Gains or losses related to changes in fair value and cash settlements for derivatives not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations, for the three and six month periods ended March 31,June 30, 2016 and 2015.

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Gain (Loss) Recognized in Derivative Income (Expense)
(In millions)
Gain (Loss) Recognized in Derivative Income (Expense)
(In millions)
 
Gain (Loss) Recognized in Derivative Income (Expense)
(In millions)
Three Months Ended
March 31,
 Three Months Ended
June 30,
 Six Months Ended
June 30,
Description2016 2015 2016 2015 2016 2015
Commodity contracts:           
Cash settlements$
 $3.1
 $
 $4.1
 $
 $7.2
Change in fair value
 (0.9) 
 (4.4) 
 (5.3)
Total gain on non-qualifying hedges$
 $2.2
 
Total gains (losses) on non-qualifying hedges$
 $(0.3) $
 $1.9
 
Offsetting of derivative assets and liabilities:
 
Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. As of March 31,June 30, 2016, andall of our derivative contracts, other than our collar contract, were in an asset position. The potential impact of the rights of offset of our collar contract was immaterial at June 30, 2016. As of December 31, 2015, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

Note 5 – Debt
 
Our debt balances (net of related unamortized discounts and debt issuance costs) as of March 31,June 30, 2016 and December 31, 2015 were as follows:
March 31,
2016
 December 31,
2015
June 30,
2016
 December 31,
2015
(In millions)(In millions)
1 34% Senior Convertible Notes due 2017
$283.5
 $279.3
$287.9
 $279.3
7 12% Senior Notes due 2022
770.2
 770.0
770.3
 770.0
Revolving credit facility457.0
 
341.5
 
4.20% Building Loan11.6
 11.7
11.5
 11.7
Total debt1,522.3
 1,061.0
1,411.2
 1,061.0
Less: current portion of long-term debt(459.2) 
(288.3) 
Long-term debt$1,063.1
 $1,061.0
$1,122.9
 $1,061.0
 
Current Portion of Long-Term Debt. As of March 31,June 30, 2016, the current portion of long-term debt of $459.2$288.3 million consisted of $283.5$287.9 million of 2017 Convertible Notes $175.3 million of outstanding borrowings under the bank credit facility (our borrowing base deficiency) and $0.4 million of principal payments due within one year on the Building Loan.

Revolving Credit Facility. On June 24, 2014, we entered into an amended and restateda revolving credit facility (the Fourth Amended and Restated Credit Agreement dated as of June 24, 2014) with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility.with an initial borrowing base of $500 million. The bank credit facility matures on July 1, 2019. On March 31, 2016, we had a $500 million borrowing base under the credit facility, with $457 million of outstanding borrowings and $19.2 million of outstanding letters of credit, leaving $23.8 million of availability under the bank credit facility. The weighted average interest rate under the bank credit facility was approximately 3.5% at March 31, 2016. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of March 31, 2016, the bank credit facility was guaranteed by Stone Energy Offshore, L.L.C. (“Stone Offshore”), SEO A LLC and SEO B LLC (collectively, the “Guarantor Subsidiaries”).
The borrowing base under the bank credit facility is redetermined semi-annually, typically by May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank credit facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. On April 13, 2016, we received notice that our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. We elected to pay the

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installments. We have not taken any action or made an electiondeficiency in six equal monthly installments, making the first payment of actions$29.2 million on May 13, 2016 and the second payment of $29.2 million on June 13, 2016.

On June 14, 2016, we entered into Amendment No. 3 (the "Amendment") to be takenthe bank credit facility to cure(i) increase the borrowing base deficiency. The $175.3to $360 million from $300 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ending September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the Amendment) of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures of $60 million for the period of June 1, 2016 through December 31, 2016, but allowing for an additional $25 million to be expended for Appalachian drilled but uncompleted wells, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50.0 million to apply after December 10, 2016. Upon execution of the Amendment, we repaid $56.8 million in borrowings under the credit facility, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation.

On June 30 and August 2, 2016, we had $341.5 million of outstanding borrowings and $18.3 million of outstanding letters of credit, leaving $0.2 million of availability under the bank credit facility. The weighted average interest rate under the bank credit facility was approximately 4.3% at June 30, 2016. Subject to certain exceptions, the bank credit facility is classified as a current liability at March 31, 2016.required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of June 30, 2016, the bank credit facility was guaranteed by Stone Energy Offshore, L.L.C. (“Stone Offshore”), SEO A LLC and SEO B LLC (collectively, the “Guarantor Subsidiaries”).
 
The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank credit facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. However, the Amendment provides for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties. The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage, and grant a security interest in, our oil and natural gas reserves representing at least 80% 86%of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Interest on loans under the bank credit facility is calculated using the London Interbank Offering (“LIBOR”) rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%.

UnderIn addition to the financial covenants ofdiscussed above, the bank credit facility provides that we must (1) maintain a ratio of Consolidated Funded Debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.75 to 1 and (2) maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 2.5 to 1. In addition, ourThe bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of March 31,June 30, 2016.

2017 Convertible Notes. On March 6, 2012, we issued in a private offering $300 million in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes are convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, based on an initial conversion rate of 23.4449 shares of our common stock per $1,000 principal amount of 2017 Convertible Notes, which correspondscorresponded to an initial conversion price of approximately $42.65 per share of our common stock. On March 31, 2016, our closing share price was $0.79 per share.stock at the time of the issuance of the 2017 Convertible Notes. The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture related to the 2017 Convertible Notes. Upon conversion, we will be obligated to pay or deliver, as the case may be, cash, shares of our common stock or a combination of cash and shares of our common stock. Prior to December 1, 2016, the 2017 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the second scheduled trading day immediately preceding the maturity date. On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock (see Note 1 – Interim Financial Statements). Proportional adjustments were made to the conversion price and shares as they relate to the 2017 Convertible Notes, resulting in a conversion rate of 2.34449 shares of our common stock with a corresponding conversion price of $426.50 per share. On June 30, 2016, our closing share price was $12.06 per share.

The 2017 Convertible Notes will be due on March 1, 2017, unless earlier converted or repurchased by us at the option of the holder(s), and interest is payable on the 2017 Convertible Notes each March 1and September 1. On the maturity date, each holder will be entitled to receive $1,000 in cash for each $1,000 in principal amount of 2017 Convertible Notes, together with any accrued and unpaid interest to, but excluding, the maturity date.

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In connection with the offering, we entered into convertible note hedge transactions with respect to our common stock (the “Purchased Call Options”) with Barclays Capital Inc., acting as agent for Barclays Bank PLC and Bank of America, N.A. (the “Dealers”). We paid an aggregate amount of approximately $70.8 million to the Dealers for the Purchased Call Options. The Purchased Call Options cover, subject to customary antidilution adjustments, approximately 7,033,470703,347 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes (after the effectiveness of the reverse stock split of 1-for-10), also subject to adjustment, and are exercisable upon conversion of the 2017 Convertible Notes.
 
We also entered into separate warrant transactions whereby, in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately 7,033,470703,347 shares of our common stock (the “Sold Warrants”) at a strike price of $55.91$559.10 per share of our common stock.stock (after the effectiveness of the reverse stock split of 1-for-10). We received aggregate proceeds of approximately $40.1 million from the sale of the Sold Warrants to the Dealers. If, upon expiration of the Sold Warrants, the price per share of our common stock, as measured under the Sold Warrants, is greater than the strike price of the Sold Warrants, we will be required to issue, without further consideration, under each Sold Warrant a number of shares of our common stock with a value equal to the amount of such difference.
 
As of March 31,June 30, 2016, the carrying amount of the liability component of the 2017 Convertible Notes of $283.5$287.9 million was classified as a current liability. During the three and six months ended March 31,June 30, 2016, we recognized $3.9$4.0 million and $7.9 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $0.8 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and six months ended March 31,June 30, 2015, we recognized $3.6$3.7 million and $7.4 million, respectively, of interest expense for the amortization of the discount and $0.3$0.4 million and $0.7 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During each of the three and six month periods ended March 31,June 30, 2016, we recognized $1.3 million and $2.6 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes. During the three and six month periods ended June 30, 2015, we recognized $1.3 million and $2.6 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.
 

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Note 6 – Asset Retirement Obligations
 
The change in our asset retirement obligations during the threesix months ended March 31,June 30, 2016 is set forth below:
Three Months Ended
March 31, 2016
Six Months Ended
June 30, 2016
(In millions)(In millions)
Asset retirement obligations as of the beginning of the period, including current portion$225.9
$225.9
Liabilities incurred2.1
2.1
Liabilities settled(4.7)(10.7)
Accretion expense10.0
20.1
Asset retirement obligations as of the end of the period, including current portion$233.3
$237.4
 
Note 7 – Income Taxes
 
As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of March 31,June 30, 2016, our valuation allowance totaled $245.5$322.8 million. Our effective tax rate for the threesix months ended March 31,June 30, 2016 was 1.0%2.1%. This percentage differed from the federal statutory rate of 35.0% primarily due to the establishment of the valuation allowancesallowance against deferred tax assets. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities. We had a current income tax receivable of $46.2 million at March 31,June 30, 2016, which relates to expected tax refunds from the carryback of net operating losses to previous tax years. Additionally, we had $3.2 million of non-current income tax receivables at June 30, 2016 reflected in Other Assets, as they aren’t expected to be received within twelve months.

Note 8 – Fair Value Measurements
 
U.S. Generally Accepted Accounting Principles establish a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly

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observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.
 
As of March 31,June 30, 2016 and December 31, 2015, we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call portion of the collar. For a more detailed description of our derivative instruments, see Note 4 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.
 
We had no liabilities measured at fair value on a recurring basis at March 31, 2016 and December 31, 2015. At June 30, 2016, we had an immaterial collar contract in a liability position, measured at fair value on a recurring basis. The following tables present our assets that are measured at fair value on a recurring basis at March 31,June 30, 2016 and December 31, 2015:2015.
Fair Value Measurements atFair Value Measurements at
March 31, 2016June 30, 2016
AssetsTotal 
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
Total 
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
(In millions)(In millions)
Marketable securities (Other assets)$8.5
 $8.5
 $
 $
$8.6
 $8.6
 $
 $
Derivative contracts30.2
 
 28.8
 1.4
11.9
 
 11.9
 
Total$38.7
 $8.5
 $28.8
 $1.4
$20.5
 $8.6
 $11.9
 $
 

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 Fair Value Measurements at
 December 31, 2015
AssetsTotal 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 (In millions)
Marketable securities (Other assets)$8.5
 $8.5
 $
 $
Derivative contracts38.6
 
 36.6
 2.0
Total$47.1
 $8.5
 $36.6
 $2.0
  
The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the threesix months ended March 31,June 30, 2016.

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 Hedging Contracts, net Hedging Contracts, net
 (In millions) (In millions)
Balance as of January 1, 2016 $2.0
 $2.0
Total gains/(losses) (realized or unrealized):    
Included in earnings 1.0
 1.1
Included in other comprehensive income (0.5) (1.9)
Purchases, sales, issuances and settlements (1.1) (1.2)
Transfers in and out of Level 3 
 
Balance as of March 31, 2016 $1.4
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at March 31, 2016 $
Balance as of June 30, 2016 $
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at June 30, 2016 $
The fair value of cash and cash equivalents approximated book value at March 31,June 30, 2016 and December 31, 2015. As of March 31,June 30, 2016 and December 31, 2015, the fair value of the liability component of the 2017 Convertible Notes was approximately $225.3$258.5 million and $217.1 million, respectively. As of March 31,June 30, 2016 and December 31, 2015, the fair value of the 7 12% Senior2022 Notes due 2022 (the “2022 Notes”) was approximately $209.3$348.8 million and $271.3 million, respectively.
 
The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see Note 5 – Debt) at inception, March 31,June 30, 2016 and December 31, 2015. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.
 

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Note 9 – Accumulated Other Comprehensive Income (Loss)
 
Changes in accumulated other comprehensive income (loss) by component for the three and six months ended March 31,June 30, 2016, were as follows (in millions):
 
Cash Flow
Hedges
 
Foreign
Currency
Items
 Total
Three Months Ended June 30, 2016     
Beginning balance, net of tax$18.7
 $
 $18.7
Other comprehensive income (loss) before reclassifications:    
Change in fair value of derivatives(8.6) 
 (8.6)
Income tax effect3.1
 
 3.1
Net of tax(5.5) 
 (5.5)
Amounts reclassified from accumulated other comprehensive income:     
Operating revenue: oil/natural gas production8.9
 
 8.9
Income tax effect(3.1) 
 (3.1)
Net of tax5.8
 
 5.8
Other comprehensive loss, net of tax(11.3) 
 (11.3)
Ending balance, net of tax$7.4
 $
 $7.4


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Cash Flow
Hedges
 
Foreign
Currency
Items
 Total
Six Months Ended June 30, 2016     
Beginning balance, net of tax$24.0
 $(6.0) $18.0
Other comprehensive income (loss) before reclassifications:     
Change in fair value of derivatives(4.0) 
 (4.0)
Income tax effect1.4
 
 1.4
Net of tax(2.6) 
 (2.6)
Amounts reclassified from accumulated other comprehensive income:     
Operating revenue: oil/natural gas production21.7
 
 21.7
Other operational expenses
 (6.0) (6.0)
Income tax effect(7.7) 
 (7.7)
Net of tax14.0
 (6.0) 8.0
Other comprehensive income (loss), net of tax(16.6) 6.0
 (10.6)
Ending balance, net of tax$7.4
 $
 $7.4

Changes in accumulated other comprehensive income (loss) by component for the three and six months ended June 30, 2015, were as follows (in millions):
Cash Flow
Hedges
 
Foreign
Currency
Items
 Total
Cash Flow
Hedges
 
Foreign
Currency
Items
 Total
Three Months Ended March 31, 2016     
Three Months Ended June 30, 2015     
Beginning balance, net of tax$24.0
 $(6.0) $18.0
$77.9
 $(7.1) $70.8
Other comprehensive income (loss) before reclassifications:    
     
Change in fair value of derivatives4.6
 
 4.6
(18.8) 
 (18.8)
Foreign currency translations
 1.3
 1.3
Income tax effect(1.6) 
 (1.6)6.9
 
 6.9
Net of tax3.0
 
 3.0
(11.9) 1.3
 (10.6)
Amounts reclassified from accumulated other comprehensive income:          
Operating revenue: oil/natural gas production12.8
 
 12.8
30.4
 
 30.4
Other operational expenses
 (6.0) (6.0)
Income tax effect(4.5) 
 (4.5)(10.9) 
 (10.9)
Net of tax8.3
 (6.0) 2.3
19.5
 
 19.5
Other comprehensive income (loss), net of tax(5.3) 6.0
 0.7
(31.4) 1.3
 (30.1)
Ending balance, net of tax$18.7
 $
 $18.7
$46.5
 $(5.8) $40.7
 
Cash Flow
Hedges
 
Foreign
Currency
Items
 TotalCash Flow
Hedges
 Foreign
Currency
Items
 Total
Three Months Ended March 31, 2015     
Six Months Ended June 30, 2015     
Beginning balance, net of tax$86.8
 $(3.5) $83.3
$86.8
 $(3.5) $83.3
Other comprehensive income (loss) before reclassifications:          
Change in fair value of derivatives22.9
 
 22.9
4.1
 
 4.1
Foreign currency translations
 (3.6) (3.6)
 (2.3) (2.3)
Income tax effect(8.2) 
 (8.2)(1.3) 
 (1.3)
Net of tax14.7
 (3.6) 11.1
2.8
 (2.3) 0.5
Amounts reclassified from accumulated other comprehensive income:          
Operating revenue: oil/natural gas production36.8
 
 36.8
67.2
 
 67.2
Income tax effect(13.2) 
 (13.2)(24.1) 
 (24.1)
Net of tax23.6
 
 23.6
43.1
 
 43.1
Other comprehensive loss, net of tax(8.9) (3.6) (12.5)(40.3) (2.3) (42.6)
Ending balance, net of tax$77.9
 $(7.1) $70.8
$46.5
 $(5.8) $40.7


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During the threesix months ended March 31,June 30, 2016, we reclassified approximately $6.0 million of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC.
Note 10 – Investment in Oil and Gas Properties
 
Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows. At June 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $118.6 million based on twelve-month average prices, net of applicable differentials, of $43.49 per Bbl of oil, $1.93 per Mcf of natural gas and $9.33 per Bbl of natural gas liquids ("NGLs"). The write-down at June 30, 2016 was decreased by $18.1 million as a result of hedges. At March 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $128.9 million based on twelve-month average prices, net of applicable differentials, of $46.72 per Bbl of oil, $2.01 per Mcf of natural gas and $13.65 per Bbl of natural gas liquids ("NGLs"),NGLs, as compared to December 31, 2015 twelve-month average prices, net of applicable differentials, of $51.16 per Bbl of oil, $2.19 per Mcf of natural gas and $16.40 per Bbl of NGLs. At March 31, 2016, the write-down of oil and gas properties also included $0.3 million related

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to our Canadian oil and gas properties, which were deemed to be fully impaired at the end of 2015. The write-down at March 31, 2016 was decreased by $23 million as a result of hedges.

Note 11 – Other Operational Expenses

Included in other operational expenses for the threesix months ended March 31,June 30, 2016 is a $6.0 million loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See Note 9 - Accumulated Other Comprehensive Income (Loss). Also included in other operational expenses for the threesix months ended March 31,June 30, 2016 are approximately $6.1$13.6 million of rig subsidy and stacking charges related to the farm out of the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and stacking chargesthe platform rig at Pompano and a $20 million charge related to the Saxon Appalachian rig.termination of our deep water drilling rig contract with Ensco.
Note 12 – Restructuring Fees
In March 2016, we retained Lazard as our financial advisor and Latham & Watkins LLP as our legal advisor to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We also retained Alvarez & Marsal to assist the Company through this process. In April 2016, the independent directors of our board of directors named current board member David T. Lawrence a Special Liaison of the Independent Directors to work together with the management team of the Company to help with assessing strategic and restructuring alternatives. Andrews Kurth LLP has also been hired as special counsel to the independent directors. Additionally, we are engaged in negotiations with financial advisors for certain holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes and in June 2016, we secured an amendment to our existing credit facility with our bank group. The legal and financial advisory costs associated with these restructuring efforts are included in the statement of operations as restructuring fees and totaled $9.4 million and $10.4 million for the three and six months ended June 30, 2016, respectively.
Note 1213 – Commitments and Contingencies
 
On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management ("BOEM") stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s current guidance to lessees.lessees at such time. BOEM's notice letters indicateindicated the amount of Stone's supplemental bonding needs could be as much as $565 million. We are in discussions with BOEM to reduce the amount of the supplemental bonding or other forms of financial assurance that the agency may require and the timing of when such bonds or financial assurances may need to be provided. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations. We currentlyobligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $223$230 million posted in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed plan would require approximately $16 million of incremental financial assurance or bonding for 2016, a majority of which may require cash collateral. Under the submitted plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan provideswill be approved by BOEM. Additionally, on July 14, 2016, BOEM issued a Notice to Lessees (“NTL”) that augments requirements for the posting some incrementalof additional financial assurances in favor of BOEMby offshore lessees. We are reviewing the new NTL and discussions on the approval and implementation of this plan are ongoing.its potential impact to Stone.





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Note 1314 – Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, "Leases (Topic 842)" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements.
In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.
Note 14 - Subsequent Event15 – New York Stock Exchange Compliance

On April 29, 2016, we were notified by the New York Stock Exchange (“NYSE”) that we were not in compliance with the NYSE's continued listing requirements, as the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price for continued listing on the NYSE under RuleSection 802.01C of the NYSE Listed Company Manual. UnderOn May 17, 2016, we were notified by the NYSE’s rules, we have six months following receiptNYSE that our average global market capitalization had been less than $50 million over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50 million, which is non-compliant with Section 802.01B of the notificationNYSE Listed Company Manual.

At the close of business on June 10, 2016, we effected a 1-for-10 reverse stock split (see Note 1 – Interim Financial Statements) in order to increase the market price per share of our common stock in order to regain compliance with the NYSE's minimum share price requirement. We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the $1.00 per share average closing price requirement, although we remain non-compliant with the $50 million market capitalization and stockholders' equity requirements. On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders' equity deficiencies to the NYSE. After our submission of the business plan, the NYSE has 45 calendar days to review the plan to determine whether we have made reasonable demonstration of our ability to come into conformity with the relevant standards within the 18-month period. The NYSE will either accept the plan, at which time we would be subject to ongoing monitoring for compliance with the plan, or not accept the plan, at which time we would be subject to suspension and delisting proceedings. If the NYSE accepts the plan, during the 18-month cure period, our shares of common stock would continue to be listed and traded on the NYSE. As of August 2, 2016, our market capitalization has been above $50 million for 25 consecutive trading days.

Note 1516 – Guarantor Financial Statements
 
Our Guarantor Subsidiaries, including Stone Offshore, SEO A LLC and SEO B LLC, are unconditional guarantors of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents unaudited condensed consolidating financial information as of March 31,June 30, 2016 and December 31, 2015 and for the three and six month periods ended March 31,June 30, 2016 and 2015 on an issuer (parent company), Guarantor Subsidiaries, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

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CONDENSED CONSOLIDATING BALANCE SHEET
MARCH 31,JUNE 30, 2016
(In thousands)
Parent 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations ConsolidatedParent 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
Assets                  
Current assets:                  
Cash and cash equivalents$367,133
 $1
 $
 $
 $367,134
$169,193
 $1
 $
 $
 $169,194
Accounts receivable57,106
 38,476
 885
 (54,282) 42,185
25,410
 31,171
 883
 (19,188) 38,276
Fair value of derivative contracts
 30,222
 
 
 30,222

 11,887
 
 
 11,887
Current income tax receivable46,174
 
 
 
 46,174
46,174
 
 
 
 46,174
Inventory535
 
 
 
 535
Other current assets6,531
 
 
 
 6,531
12,080
 
 
 
 12,080
Total current assets477,479
 68,699
 885
 (54,282) 492,781
252,857
 43,059
 883
 (19,188) 277,611
Oil and gas properties, full cost method:                  
Proved1,891,423
 7,544,791
 45,645
 
 9,481,859
1,907,347
 7,565,003
 45,895
 
 9,518,245
Less: accumulated DD&A(1,891,423) (6,859,344) (45,645) 
 (8,796,412)(1,907,326) (7,007,219) (45,895) 
 (8,960,440)
Net proved oil and gas properties
 685,447
 
 
 685,447
21
 557,784
 
 
 557,805
Unevaluated261,724
 159,705
 
 
 421,429
261,971
 163,233
 
 
 425,204
Other property and equipment, net28,667
 
 
 
 28,667
27,968
 
 
 
 27,968
Other assets, net17,460
 797
 
 
 18,257
27,445
 738
 
 
 28,183
Investment in subsidiary614,540
 
 
 (614,540) 
503,738
 
 
 (503,738) 
Total assets$1,399,870
 $914,648
 $885
 $(668,822)
$1,646,581
$1,074,000
 $764,814
 $883
 $(522,926)
$1,316,771
Liabilities and Stockholders’ Equity                  
Current liabilities:                  
Accounts payable to vendors$24,915
 $67,567
 $
 $(54,282) $38,200
$23,153
 $24,950
 $
 $(19,189) $28,914
Undistributed oil and gas proceeds2,800
 1,075
 
 
 3,875
4,379
 692
 
 
 5,071
Accrued interest22,901
 
 
 
 22,901
9,773
 
 
 
 9,773
Fair value of derivative contracts
 37
 
 
 37
Asset retirement obligations
 23,465
 
 
 23,465

 33,695
 
 
 33,695
Current portion of long-term debt459,201
 
 
 
 459,201
288,336
 
 
 
 288,336
Other current liabilities32,335
 336
 
 
 32,671
34,513
 280
 
 
 34,793
Total current liabilities542,152
 92,443
 
 (54,282) 580,313
360,154
 59,654
 
 (19,189) 400,619
Long-term debt1,063,090
 
 
 
 1,063,090
1,122,901
 
 
 
 1,122,901
Asset retirement obligations1,298
 208,550
 
 
 209,848
1,355
 202,306
 
 
 203,661
Other long-term liabilities18,329
 
 
 
 18,329
18,446
 

 
 
 18,446
Total liabilities1,624,869
 300,993
 
 (54,282) 1,871,580
1,502,856
 261,960
 
 (19,189) 1,745,627
Commitments and contingencies
 
 
 
 

 
 
 
 
Stockholders’ equity:                  
Common stock558
 
 
 
 558
56
 
 
 
 56
Treasury stock(860) 
 
 
 (860)(860) 
 
 
 (860)
Additional paid-in capital1,650,969
 1,344,577
 109,077
 (1,453,654) 1,650,969
1,654,731
 1,344,577
 109,078
 (1,453,655) 1,654,731
Accumulated deficit(1,894,407) (749,663) (108,192) 857,855
 (1,894,407)(2,090,168) (849,108) (108,195) 957,303
 (2,090,168)
Accumulated other comprehensive income18,741
 18,741
 
 (18,741) 18,741
7,385
 7,385
 
 (7,385) 7,385
Total stockholders’ equity(224,999) 613,655
 885
 (614,540) (224,999)(428,856) 502,854
 883
 (503,737) (428,856)
Total liabilities and stockholders’ equity$1,399,870
 $914,648
 $885
 $(668,822) $1,646,581
$1,074,000
 $764,814
 $883
 $(522,926) $1,316,771



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CONDENSED CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2015
(In thousands)
Parent 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations ConsolidatedParent 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
Assets                  
Current assets:                  
Cash and cash equivalents$9,681
 $2
 $1,076
 $
 $10,759
$9,681
 $2
 $1,076
 $
 $10,759
Accounts receivable10,597
 39,190
 
 (1,756) 48,031
10,597
 39,190
 
 (1,756) 48,031
Fair value of derivative contracts
 38,576
 
 
 38,576

 38,576
 
 
 38,576
Current income tax receivable46,174
 
 
 
 46,174
46,174
 
 
 
 46,174
Inventory535
 
 
 
 535
Other current assets6,313
 
 33
 
 6,346
6,848
 
 33
 
 6,881
Total current assets73,300
 77,768
 1,109
 (1,756) 150,421
73,300
 77,768
 1,109
 (1,756) 150,421
Oil and gas properties, full cost method:                  
Proved1,875,152
 7,458,262
 42,484
 
 9,375,898
1,875,152
 7,458,262
 42,484
 
 9,375,898
Less: accumulated DD&A(1,874,622) (6,686,849) (42,484) 
 (8,603,955)(1,874,622) (6,686,849) (42,484) 
 (8,603,955)
Net proved oil and gas properties530
 771,413
 
 
 771,943
530
 771,413
 
 
 771,943
Unevaluated253,308
 186,735
 
 
 440,043
253,308
 186,735
 
 
 440,043
Other property and equipment, net29,289
 
 
 
 29,289
29,289
 
 
 
 29,289
Other assets, net16,612
 826
 1,035
 
 18,473
16,612
 826
 1,035
 
 18,473
Investment in subsidiary745,033
 
 1,088
 (746,121) 
745,033
 
 1,088
 (746,121) 
Total assets$1,118,072
 $1,036,742
 $3,232
 $(747,877) $1,410,169
$1,118,072
 $1,036,742
 $3,232
 $(747,877) $1,410,169
Liabilities and Stockholders’ Equity                  
Current liabilities:                  
Accounts payable to vendors$16,063
 $67,901
 $
 $(1,757) $82,207
$16,063
 $67,901
 $
 $(1,757) $82,207
Undistributed oil and gas proceeds5,216
 776
 
 
 5,992
5,216
 776
 
 
 5,992
Accrued interest9,022
 
 
 
 9,022
9,022
 
 
 
 9,022
Asset retirement obligations
 20,400
 891
 
 21,291

 20,400
 891
 
 21,291
Other current liabilities40,161
 551
 
 
 40,712
40,161
 551
 
 
 40,712
Total current liabilities70,462
 89,628
 891
 (1,757) 159,224
70,462
 89,628
 891
 (1,757) 159,224
Long-term debt1,060,955
 
 
 
 1,060,955
1,060,955
 
 
 
 1,060,955
Asset retirement obligations1,240
 203,335
 
 
 204,575
1,240
 203,335
 
 
 204,575
Other long-term liabilities25,204
 
 
 
 25,204
25,204
 
 
 
 25,204
Total liabilities1,157,861
 292,963
 891
 (1,757) 1,449,958
1,157,861
 292,963
 891
 (1,757) 1,449,958
Commitments and contingencies
 
 
 
 

 
 
 
 
Stockholders’ equity:                  
Common stock553
 
 
 
 553
55
 
 
 
 55
Treasury stock(860) 
 
 
 (860)(860) 
 
 
 (860)
Additional paid-in capital1,648,189
 1,344,577
 109,795
 (1,454,372) 1,648,189
1,648,687
 1,344,577
 109,795
 (1,454,372) 1,648,687
Accumulated deficit(1,705,623) (624,824) (95,306) 720,130
 (1,705,623)(1,705,623) (624,824) (95,306) 720,130
 (1,705,623)
Accumulated other comprehensive income (loss)17,952
 24,026
 (12,148) (11,878) 17,952
17,952
 24,026
 (12,148) (11,878) 17,952
Total stockholders’ equity(39,789) 743,779
 2,341
 (746,120) (39,789)(39,789) 743,779
 2,341
 (746,120) (39,789)
Total liabilities and stockholders’ equity$1,118,072
 $1,036,742
 $3,232
 $(747,877) $1,410,169
$1,118,072
 $1,036,742
 $3,232
 $(747,877) $1,410,169




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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2016
(In thousands)
 Parent 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
Operating revenue:         
Oil production$61
 $60,214
 $
 $
 $60,275
Natural gas production2,467
 12,706
 
 
 15,173
Natural gas liquids production1,134
 3,601
 
 
 4,735
Other operational income356
 
 
 
 356
Derivative income, net
 138
 
 
 138
Total operating revenue4,018
 76,659
 
 
 80,677
Operating expenses:         
Lease operating expenses2,728
 16,806
 13
 
 19,547
Transportation, processing and gathering expenses1,546
 (705) 
 
 841
Production taxes259
 222
 
 
 481
Depreciation, depletion and amortization8,594
 52,964
 
 
 61,558
Write-down of oil and gas properties9,324
 119,531
 349
 
 129,204
Accretion expense58
 9,925
 
 
 9,983
Salaries, general and administrative expenses13,907
 (200) 
 
 13,707
Incentive compensation expense4,979
 
 
 
 4,979
Other operational expenses6,109
 337
 6,081
 
 12,527
Total operating expenses47,504
 198,880
 6,443
 
 252,827
Loss from operations(43,486) (122,221) (6,443) 
 (172,150)
Other (income) expenses:         
Interest expense15,241
 
 
 
 15,241
Interest income(114) 
 
 
 (114)
Other income(39) (259) 
 
 (298)
Other expense2
 
 
 
 2
Loss from investment in subsidiaries131,282
 
 6,443
 (137,725) 
Total other (income) expenses146,372
 (259) 6,443
 (137,725) 14,831
Loss before taxes(189,858) (121,962) (12,886) 137,725
 (186,981)
Provision (benefit) for income taxes:         
Current(1,074) 
 
 
 (1,074)
Deferred
 2,877
 
 
 2,877
Total income taxes(1,074) 2,877
 
 
 1,803
Net loss$(188,784) $(124,839) $(12,886) $137,725
 $(188,784)
Comprehensive loss$(187,995) $(124,839) $(12,886) $137,725
 $(187,995)


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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2015
(In thousands)
 Parent 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
Operating revenue:         
Oil production$4,350
 $103,157
 $
 $
 $107,507
Natural gas production16,617
 11,720
 
 
 28,337
Natural gas liquids production9,879
 2,487
 
 
 12,366
Other operational income2,160
 
 
 
 2,160
Derivative income, net
 3,128
 
 
 3,128
Total operating revenue33,006
 120,492
 
 
 153,498
Operating expenses:         
Lease operating expenses4,976
 22,601
 
 
 27,577
Transportation, processing and gathering expenses16,108
 1,595
 
 
 17,703
Production taxes2,198
 317
 
 
 2,515
Depreciation, depletion and amortization42,112
 44,310
 
 
 86,422
Write-down of oil and gas properties491,412
 
 
 
 491,412
Accretion expense91
 6,318
 
 
 6,409
Salaries, general and administrative expenses17,001
 1
 5
 
 17,007
Incentive compensation expense1,563
 
 
 
 1,563
Other operational expenses84
 
 
 
 84
Total operating expenses575,545
 75,142
 5
 
 650,692
Income (loss) from operations(542,539) 45,350
 (5) 
 (497,194)
Other (income) expenses:         
Interest expense10,344
 21
 
 
 10,365
Interest income(101) (16) (5) 
 (122)
Other income(133) (10) 
 
 (143)
Income from investment in subsidiaries(29,027) 
 
 29,027
 
Total other (income) expenses(18,917) (5) (5) 29,027
 10,100
Income (loss) before taxes(523,622) 45,355
 
 (29,027) (507,294)
Provision (benefit) for income taxes:         
Deferred(196,234) 16,328
 
 
 (179,906)
Total income taxes(196,234) 16,328
 
 
 (179,906)
Net income (loss)$(327,388) $29,027
 $
 $(29,027) $(327,388)
Comprehensive income (loss)$(339,891) $29,027
 $
 $(29,027) $(339,891)



18


Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWSOPERATIONS
THREE MONTHS ENDED MARCH 31,JUNE 30, 2016
(In thousands)
 Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Cash flows from operating activities:         
Net loss$(188,784) $(124,839) $(12,886) $137,725
 $(188,784)
Adjustments to reconcile net loss to net cash provided by operating activities:         
Depreciation, depletion and amortization8,594
 52,964
 
 
 61,558
Write-down of oil and gas properties9,324
 119,531
 349
 
 129,204
Accretion expense58
 9,925
 
 
 9,983
Deferred income tax provision
 2,877
 
 
 2,877
Settlement of asset retirement obligations
 (3,768) (899) 
 (4,667)
Non-cash stock compensation expense2,312
 
 
 
 2,312
Non-cash derivative expense
 192
 
 
 192
Non-cash interest expense4,635
 
 
 
 4,635
Other non-cash expense
 
 6,081
 
 6,081
Change in current income taxes(1,074) 
 
 
 (1,074)
Non-cash loss from investment in subsidiaries131,282
 
 6,443
 (137,725) 
Change in intercompany receivables/payables(1,657) 1,657
 
 
 
(Increase) decrease in accounts receivable(36,703) 43,432
 (884) 
 5,845
(Increase) decrease in other current assets(218) 
 33
 
 (185)
Increase (decrease) in accounts payable45
 (2,183) 
 
 (2,138)
Increase in other current liabilities3,813
 85
 
 
 3,898
Other(39) (259) 
 
 (298)
Net cash (used in) provided by operating activities(68,412) 99,614
 (1,763) 
 29,439
Cash flows from investing activities:         
Investment in oil and gas properties(29,895) (99,615) (349) 
 (129,859)
Investment in fixed and other assets(496) 
 
 
 (496)
Change in restricted funds
 
 1,045
 
 1,045
Investment in subsidiaries
 
 718
 (718) 
Net cash (used in) provided by investing activities(30,391) (99,615) 1,414
 (718) (129,310)
Cash flows from financing activities:         
Proceeds from bank borrowings477,000
 
 
 
 477,000
Repayments of bank borrowings(20,000) 
 
 
 (20,000)
Repayments of building loan(95) 
 
 
 (95)
Equity proceeds from parent
 
 (718) 718
 
Net payments for share-based compensation(650) 
 
 
 (650)
Net cash provided by (used in) financing activities456,255
 
 (718)
718

456,255
Effect of exchange rate changes on cash
 
 (9) 
 (9)
Net change in cash and cash equivalents357,452
 (1) (1,076) 
 356,375
Cash and cash equivalents, beginning of period9,681
 2
 1,076
 
 10,759
Cash and cash equivalents, end of period$367,133
 $1
 $
 $
 $367,134
 Parent Guarantor
Subsidiaries
 Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
Operating revenue:         
Oil production$1,323
 $71,388
 $
 $
 $72,711
Natural gas production3,959
 8,594
 
 
 12,553
Natural gas liquids production2,375
 1,343
 
 
 3,718
Other operational income337
 
 
 
 337
Total operating revenue7,994
 81,325
 
 
 89,319
Operating expenses:         
Lease operating expenses3,814
 15,012
 
 
 18,826
Transportation, processing and gathering expenses6,021
 1,162
 
 
 7,183
Production taxes383
 195
 
 
 578
Depreciation, depletion and amortization10,470
 35,761
 
 
 46,231
Write-down of oil and gas properties6,534
 112,114
 1
 
 118,649
Accretion expense58
 10,024
 
 
 10,082
Salaries, general and administrative expenses20,013
 1
 
 
 20,014
Incentive compensation expense4,670
 
 
 
 4,670
Restructuring fees9,436
 
 
 
 9,436
Other operational expenses27,736
 (57) 1
 
 27,680
Derivative expense, net
 626
 
 
 626
Total operating expenses89,135
 174,838
 2
 
 263,975
Loss from operations(81,141) (93,513) (2) 
 (174,656)
Other (income) expenses:         
Interest expense17,599
 
 
 
 17,599
Interest income(302) 
 
 
 (302)
Other income(20) (250) 
 
 (270)
Other expense9
 
 
 
 9
Loss from investment in subsidiaries99,447
 
 1
 (99,448) 
Total other (income) expenses116,733
 (250) 1
 (99,448) 17,036
Loss before taxes(197,874) (93,263) (3) 99,448
 (191,692)
Provision (benefit) for income taxes:         
Current(2,113) 
 
 
 (2,113)
Deferred
 6,182
 
 
 6,182
Total income taxes(2,113) 6,182
 
 
 4,069
Net loss$(195,761) $(99,445) $(3) $99,448
 $(195,761)
Comprehensive loss$(207,117) $(99,445) $(3) $99,448
 $(207,117)


19


Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWSOPERATIONS
THREE MONTHS ENDED MARCH 31,JUNE 30, 2015
(In thousands)
 Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Cash flows from operating activities:         
Net income (loss)$(327,388) $29,027
 $
 $(29,027) $(327,388)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:         
Depreciation, depletion and amortization42,112
 44,310
 
 
 86,422
Write-down of oil and gas properties491,412
 
 
 
 491,412
Accretion expense91
 6,318
 
 
 6,409
Deferred income tax (benefit) provision(196,234) 16,328
 
 
 (179,906)
Settlement of asset retirement obligations(1) (17,144) 
 
 (17,145)
Non-cash stock compensation expense2,640
 
 
 
 2,640
Non-cash derivative expense
 1,511
 
 
 1,511
Non-cash interest expense4,318
 
 
 
 4,318
Change in current income taxes7,188
 
 
 
 7,188
Non-cash income from investment in subsidiaries(29,027) 
 
 29,027
 
Change in intercompany receivables/payables(33,748) 25,548
 8,200
 
 
Decrease in accounts receivable3,606
 4,600
 
 
 8,206
Decrease in other current assets1,881
 
 2
 
 1,883
(Increase) decrease in inventory(2,415) 2,415
 
 
 
Decrease in accounts payable(1,007) (7,650) 
 
 (8,657)
Increase in other current liabilities6,347
 542
 
 
 6,889
Other(249) (11) 
 
 (260)
Net cash (used in) provided by operating activities(30,474) 105,794
 8,202
 
 83,522
Cash flows from investing activities:         
Investment in oil and gas properties(84,470) (77,229) (8,196) 
 (169,895)
Investment in fixed and other assets(662) 
 
 
 (662)
Change in restricted funds177,647
 
 (5) 
 177,642
Investment in subsidiaries
 
 (8,168) 8,168
 
Net cash provided by (used in) investing activities92,515
 (77,229) (16,369) 8,168
 7,085
Cash flows from financing activities:         
Proceeds from bank borrowings5,000
 
 
 
 5,000
Repayments of bank borrowings(5,000) 
 
 
 (5,000)
Equity proceeds from parent
 
 8,168
 (8,168) 
Net payments for share-based compensation(2,991) 
 
 
 (2,991)
Net cash (used in) provided by financing activities(2,991) 
 8,168
 (8,168) (2,991)
Effect of exchange rate changes on cash
 
 24
 
 24
Net change in cash and cash equivalents59,050
 28,565
 25
 
 87,640
Cash and cash equivalents, beginning of period72,886
 1,450
 152
 
 74,488
Cash and cash equivalents, end of period$131,936
 $30,015
 $177
 $
 $162,128
 Parent 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
Operating revenue:         
Oil production$6,504
 $105,081
 $
 $
 $111,585
Natural gas production15,647
 11,260
 
 
 26,907
Natural gas liquids production8,077
 2,956
 
 
 11,033
Total operating revenue30,228
 119,297
 
 
 149,525
Operating expenses:         
Lease operating expenses5,111
 22,318
 
 
 27,429
Transportation, processing and gathering expenses17,974
 1,966
 
 
 19,940
Production taxes1,436
 391
 
 
 1,827
Depreciation, depletion and amortization44,052
 33,899
 
 
 77,951
Write-down of oil and gas properties179,125
 
 45,169
 
 224,294
Accretion expense91
 6,317
 
 
 6,408
Salaries, general and administrative expenses16,398
 
 20
 
 16,418
Incentive compensation expense1,264
 
 
 
 1,264
Other operational expenses1,454
 
 
 
 1,454
Derivative expense, net
 701
 
 
 701
Total operating expenses266,905
 65,592
 45,189
 
 377,686
Income (loss) from operations(236,677) 53,705
 (45,189) 
 (228,161)
Other (income) expenses:         
Interest expense10,472
 
 
 
 10,472
Interest income(46) (19) (1) 
 (66)
Other income(187) (423) (3) 
 (613)
(Income) loss from investment in subsidiaries(16,147) 
 28,918
 (12,771) 
Total other (income) expenses(5,908) (442) 28,914
 (12,771) 9,793
Income (loss) before taxes(230,769) 54,147
 (74,103) 12,771
 (237,954)
Provision (benefit) for income taxes:         
Deferred(77,863) 9,082
 (16,267) 
 (85,048)
Total income taxes(77,863) 9,082
 (16,267) 
 (85,048)
Net income (loss)$(152,906) $45,065
 $(57,836) $12,771
 $(152,906)
Comprehensive income (loss)$(183,062) $45,065
 $(57,836) $12,771
 $(183,062)


20


Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2016
(In thousands)
 Parent Guarantor
Subsidiaries
 Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
Operating revenue:         
Oil production$1,384
 $131,602
 $
 $
 $132,986
Natural gas production6,426
 21,300
 
 
 27,726
Natural gas liquids production3,509
 4,944
 
 
 8,453
Other operational income693
 
 
 
 693
Total operating revenue12,012
 157,846
 
 
 169,858
Operating expenses:         
Lease operating expenses6,542
 31,818
 13
 
 38,373
Transportation, processing and gathering expenses7,567
 457
 
 
 8,024
Production taxes642
 417
 
 
 1,059
Depreciation, depletion and amortization19,064
 88,725
 
 
 107,789
Write-down of oil and gas properties15,858
 231,645
 350
 
 247,853
Accretion expense116
 19,949
 
 
 20,065
Salaries, general and administrative expenses32,967
 (199) 
 
 32,768
Incentive compensation expense9,649
 
 
 
 9,649
Restructuring fees10,389
 
 
 
 10,389
Other operational expenses33,845
 280
 6,082
 
 40,207
Derivative expense, net
 488
 
 
 488
Total operating expenses136,639
 373,580
 6,445
 
 516,664
Loss from operations(124,627) (215,734) (6,445) 
 (346,806)
Other (income) expenses:         
Interest expense32,840
 
 
 
 32,840
Interest income(416) 
 
 
 (416)
Other income(59) (509) 
 
 (568)
Other expense11
 
 
 
 11
Loss from investment in subsidiaries230,729
 
 6,444
 (237,173) 
Total other (income) expenses263,105
 (509) 6,444
 (237,173) 31,867
Loss before taxes(387,732) (215,225) (12,889) 237,173
 (378,673)
Provision (benefit) for income taxes:         
Current(3,187) 
 
 
 (3,187)
Deferred
 9,059
 
 
 9,059
Total income taxes(3,187) 9,059
 
 
 5,872
Net loss$(384,545) $(224,284) $(12,889) $237,173
 $(384,545)
Comprehensive loss$(395,112) $(224,284) $(12,889) $237,173
 $(395,112)


21


Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2015
(In thousands)
 Parent 
Guarantor
Subsidiaries
 
Non-
Guarantor
Subsidiaries
 Eliminations Consolidated
Operating revenue:         
Oil production$10,854
 $208,238
 $
 $
 $219,092
Natural gas production32,264
 22,980
 
 
 55,244
Natural gas liquids production17,956
 5,443
 
 
 23,399
Other operational income1,792
 
 
 
 1,792
Derivative income, net
 2,427
 
 
 2,427
Total operating revenue62,866
 239,088
 
 
 301,954
Operating expenses:         
Lease operating expenses10,087
 44,919
 
 
 55,006
Transportation, processing and gathering expenses34,082
 3,561
 
 
 37,643
Production taxes3,634
 708
 
 
 4,342
Depreciation, depletion and amortization86,164
 78,209
 
 
 164,373
Write-down of oil and gas properties670,537
 
 45,169
 
 715,706
Accretion expense182
 12,635
 
 
 12,817
Salaries, general and administrative expenses33,399
 1
 25
 
 33,425
Incentive compensation expense2,827
 
 
 
 2,827
Other operational expenses1,170
 
 
 
 1,170
Total operating expenses842,082
 140,033
 45,194
 
 1,027,309
Income (loss) from operations(779,216) 99,055
 (45,194) 
 (725,355)
Other (income) expenses:         
Interest expense20,816
 21
 
 
 20,837
Interest income(147) (35) (6) 
 (188)
Other income(320) (433) (3) 
 (756)
(Income) loss from investment in subsidiaries(45,174) 
 28,918
 16,256
 
Total other (income) expenses(24,825) (447) 28,909
 16,256
 19,893
Income (loss) before taxes(754,391) 99,502
 (74,103) (16,256) (745,248)
Provision (benefit) for income taxes:         
Deferred(274,097) 25,410
 (16,267) 
 (264,954)
Total income taxes(274,097) 25,410
 (16,267) 
 (264,954)
Net income (loss)$(480,294) $74,092
 $(57,836) $(16,256) $(480,294)
Comprehensive income (loss)$(522,953) $74,092
 $(57,836) $(16,256) $(522,953)


22


Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
SIX MONTHS ENDED JUNE 30, 2016
(In thousands)
 Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Cash flows from operating activities:         
Net loss$(384,545) $(224,284) $(12,889) $237,173
 $(384,545)
Adjustments to reconcile net loss to net cash provided by operating activities:         
Depreciation, depletion and amortization19,064
 88,725
 
 
 107,789
Write-down of oil and gas properties15,858
 231,645
 350
 
 247,853
Accretion expense116
 19,949
 
 
 20,065
Deferred income tax provision
 9,059
 
 
 9,059
Settlement of asset retirement obligations
 (9,807) (899) 
 (10,706)
Non-cash stock compensation expense4,682
 
 
 
 4,682
Non-cash derivative expense
 1,025
 
 
 1,025
Non-cash interest expense9,403
 
 
 
 9,403
Other non-cash expense
 
 6,081
 
 6,081
Change in current income taxes(3,187) 
 
 
 (3,187)
Non-cash loss from investment in subsidiaries230,729
 
 6,444
 (237,173) 
Change in intercompany receivables/payables(1,658) 1,658
 
 
 
(Increase) decrease in accounts receivable(8,471) 19,109
 (883) 
 9,755
(Increase) decrease in other current assets(5,316) 
 33
 
 (5,283)
Increase (decrease) in accounts payable2,226
 (2,547) 
 
 (321)
Decrease in other current liabilities(5,565) (355) 
 
 (5,920)
Other(7,372) (508) 
 
 (7,880)
Net cash (used in) provided by operating activities(134,036) 133,669
 (1,763) 
 (2,130)
Cash flows from investing activities:         
Investment in oil and gas properties(45,292) (133,670) (349) 
 (179,311)
Investment in fixed and other assets(898) 
 
 
 (898)
Change in restricted funds
 
 1,045
 
 1,045
Investment in subsidiaries
 
 717
 (717) 
Net cash (used in) provided by investing activities(46,190) (133,670) 1,413
 (717) (179,164)
Cash flows from financing activities:         
Proceeds from bank borrowings477,000
 
 
 
 477,000
Repayments of bank borrowings(135,500) 
 
 
 (135,500)
Repayments of building loan(189) 
 
 
 (189)
Deferred financing costs(900) 
 
 
 (900)
Equity proceeds from parent
 
 (717) 717
 
Net payments for share-based compensation(673) 
 
 
 (673)
Net cash provided by (used in) financing activities339,738
 
 (717)
717

339,738
Effect of exchange rate changes on cash
 
 (9) 
 (9)
Net change in cash and cash equivalents159,512
 (1) (1,076) 
 158,435
Cash and cash equivalents, beginning of period9,681
 2
 1,076
 
 10,759
Cash and cash equivalents, end of period$169,193
 $1
 $
 $
 $169,194

23


Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
SIX MONTHS ENDED JUNE 30, 2015
(In thousands)
 Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Cash flows from operating activities:         
Net income (loss)$(480,294) $74,092
 $(57,836) $(16,256) $(480,294)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:         
Depreciation, depletion and amortization86,164
 78,209
 
 
 164,373
Write-down of oil and gas properties670,537
 
 45,169
 
 715,706
Accretion expense182
 12,635
 
 
 12,817
Deferred income tax (benefit) provision(274,097) 25,410
 (16,267) 
 (264,954)
Settlement of asset retirement obligations(14) (35,909) 
 
 (35,923)
Non-cash stock compensation expense6,028
 
 
 
 6,028
Non-cash derivative expense
 7,931
 
 
 7,931
Non-cash interest expense8,737
 
 
 
 8,737
Change in current income taxes7,206
 
 
 
 7,206
Non-cash (income) expense from investment in subsidiaries(45,174) 
 28,918
 16,256
 
Change in intercompany receivables/payables15,070
 (24,802) 9,732
 
 
Decrease in accounts receivable16,968
 6,079
 
 
 23,047
Increase in other current assets(1,895) 
 (64) 
 (1,959)
(Increase) decrease in inventory(2,415) 2,415
 
 
 
Decrease in accounts payable(500) (7,326) 
 
 (7,826)
Decrease in other current liabilities(8,409) (311) 
 
 (8,720)
Other(71) (433) 
 
 (504)
Net cash (used in) provided by operating activities(1,977) 137,990
 9,652
 
 145,665
Cash flows from investing activities:         
Investment in oil and gas properties(128,333) (124,506) (11,516) 
 (264,355)
Proceeds from sale of oil and gas properties, net of expenses
 10,100
 
 
 10,100
Investment in fixed and other assets(727) 
 
 
 (727)
Change in restricted funds177,647
 
 1,828
 
 179,475
Investment in subsidiaries
 
 (9,684) 9,684
 
Net cash provided by (used in) investing activities48,587
 (114,406) (19,372) 9,684
 (75,507)
Cash flows from financing activities:         
Proceeds from bank borrowings5,000
 
 
 
 5,000
Repayments of bank borrowings(5,000) 
 
 
 (5,000)
Equity proceeds from parent
 
 9,684
 (9,684) 
Net payments for share-based compensation(3,069) 
 
 
 (3,069)
Net cash (used in) provided by financing activities(3,069) 
 9,684
 (9,684) (3,069)
Effect of exchange rate changes on cash
 
 78
 
 78
Net change in cash and cash equivalents43,541
 23,584
 42
 
 67,167
Cash and cash equivalents, beginning of period72,886
 1,450
 152
 
 74,488
Cash and cash equivalents, end of period$116,427
 $25,034
 $194
 $
 $141,655

24


Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Statements
The information in this Quarterly Report on Form 10-Q (this “Form 10-Q”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements as described in our 2015 Annual Report on Form 10-K and in this Form 10-Q.
Forward-looking statements may appear in a number of places in this Form 10-Q and include statements with respect to, among other things:
any expected results or benefits associated with our acquisitions;
expected results from risk-weighted drilling success;
estimates of our future oil and natural gas production, including estimates of any increases in oil and natural gas production;
planned capital expenditures and the availability of capital resources to fund capital expenditures;
our outlook on oil and natural gas prices;
estimates of our oil and natural gas reserves;
any estimates of future earnings growth;
the impact of political and regulatory developments;
our outlook on the resolution of pending litigation and government inquiry;
estimates of the impact of new accounting pronouncements on earnings in future periods;
our future financial condition or results of operations and our future revenues and expenses;
the outcome of restructuring efforts and asset sales;
the amount, nature and timing of any potential acquisition or divestiture transactions;
any expected results or benefits associated with our acquisitions;
our access to capital and our anticipated liquidity;
estimates of future income taxes; and
our business strategy and other plans and objectives for future operations.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, among other things:
 
commodity price volatility, including further or sustained declines in the prices we receive for our oil and natural gas production;
consequences of a catastrophic event like the Deepwater Horizon oil spill;
domestic and worldwide economic conditions, which may adversely affect the demand for and supply of oil and natural gas;
the availability of capital on economic terms to fund our operations, capital expenditures, acquisitions and other obligations;
our future level of indebtedness, liquidity, compliance with debt covenants and our ability to continue as a going concern;
our future financial condition, results of operations, revenues, cash flows and expenses;
the potential need to sell certain assets, restructure our debt, raise additional capital or seek bankruptcy protection;
our ability to continue to borrow under our credit facility;
our ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by BOEM;
declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our bank credit facility and impairments;
our ability to develop, explore for, acquire and replace oil and natural gas reserves and and sustain production;
the impact of a financial crisis on our business operations, financial condition and ability to raise capital;
the ability of financial counterparties to perform or fulfill their obligations under existing agreements;
third-party interruption of sales to market;
inflation;
lack of availability and cost of goods and services;
market conditions relating to potential acquisition and divestiture transactions;
regulatory and environmental risks associated with drilling and production activities, including, for example, compliance with the Bureau of Safety and Environmental Enforcement's recently finalized well control rule;
our ability to establish operations or production on our acreage prior to the expiration of related leaseholds;
availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;
competition in the oil and gas industry;
our inability to retain and attract key personnel;

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drilling and other operating risks;risks, including the consequences of a catastrophic event;
unsuccessful exploration and development drilling activities;
hurricanes and other weather conditions;
availability, cost and adequacy of insurance coverage;
adverse effects of changes in applicable tax, environmental, derivatives, permitting, bonding and other regulatory requirements and legislation, as well as agency interpretation and enforcement and judicial decisions regarding the foregoing, including changes affecting our offshore and Appalachian operations;
uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and
other risks described in this Form 10-Q.
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, Item 1A. Risk Factors, of this Form 10-Q and (2) Part I, Item 1A, of our 2015 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2015 Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in this Form 10-Q should be read in conjunction with the MD&A contained in our 2015 Annual Report on Form 10-K. 
Critical Accounting Estimates
Our 2015 Annual Report on Form 10-K describes the accounting estimates that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments. Our most significant estimates are:
 
remaining proved oil and natural gas reserve volumes and the timing of their production;
estimated costs to develop and produce proved oil and natural gas reserves;
accruals of exploration costs, development costs, operating costs and production revenue;
timing and future costs to abandon our oil and gas properties;
effectiveness and estimated fair value of derivative positions;
classification of unevaluated property costs;
capitalized general and administrative costs and interest;
estimates of fair value in business combinations;
current and deferred income taxes; and
contingencies.
This Form 10-Q should be read together with the discussion contained in our 2015 Annual Report on Form 10-K regarding these critical accounting policies.
Other Factors Affecting Our Business and Financial Results
In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our 2015 Annual Report on Form 10-K and in this Form 10-Q under Part II, Item 1A. Risk Factors, regarding our known material risk factors.
Overview
We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia.
We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016 and shut in our Mary field in Appalachia in September 2015. The lower commodity prices have negatively impacted our liquidity position. Additionally, the level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of May 4,August 2, 2016, we had total indebtedness of $1,544$1,428 million, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes, $457$341.5 million outstanding under our bank credit facility and $12$11.5 million outstanding under our Building Loan. As of March 31, 2016, we were in compliance with all of our financial covenants under our bank credit facility and the indentures governing our outstanding notes.However, given the lower

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commodity prices and our reduced hedged position inOn March 10, 2016, we anticipate that we will exceed the Consolidated Funded Debt to consolidated EBITDA financial covenant of 3.75 to 1 set forth inborrowed $385 million under our bank credit agreementfacility, which at the endtime, represented substantially all of the second quarter of 2016, which would require us to seek a waiver or amendment fromundrawn amount on our bank lenders. Additionally, on$500 million borrowing base. On April 13, 2016, the borrowing base under our bank credit facility was reduced by the lenders from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. Our agreement withIn June 2016, however, we entered into the banksAmendment to our bank credit facility which, among other things, resulted in an increase of our borrowing base from $300 million to $360 million and relaxed certain financial covenants through December 31, 2016. In addition, the Amendment requires that we maintain minimum liquidity (as defined in the Amendment) of $125.0 million through January 15, 2017, imposes limitations on capital expenditures from June to December 2016 and provides that within 30 daysfor anti-hoarding cash provisions for amounts in excess of $50.0 million beginning after notificationDecember 10, 2016. Upon execution of athe Amendment, we repaid the balance of our borrowing base deficiency, resulting in approximately $360 million outstanding under the credit facility at that time. As of June 30, 2016, we must electwere in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to curemeet our interest payment obligation on the borrowing base deficiency through any combination2022 Notes in the fourth quarter of certain actions, described2016 as well as the subsequent maturity of our 2017 Convertible Notes in more detail below underMarch 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. See "Liquidity and Capital Resources". The $175.3 million borrowing base deficiency is classified as a current liability at March 31, 2016..

In Marchlate June 2016, we terminated our deep water drilling rig contract with Ensco for total consideration of $20 million. Additionally, in late June 2016, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, allowing us to resume production at the Mary field. See "Liquidity and Capital Resources".
We have retained Lazard as our financial advisor and Latham & Watkins LLP as our legal advisor to assist the companyCompany in analyzing and considering financial, transactional and strategic alternatives. We also retained Alvarez & Marsal to assist the Company through this process. Additionally, in April 2016, the independent directors of our board of directors named current board member David T. Lawrence as a Special Liaison of the Independent Directors to work together with the management team of the company to help with assessing strategic and restructuring alternatives. Andrews Kurth LLP has also been hired as special counsel to the independent directors.
We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, asset sales and a prepackaged or prearranged bankruptcy filing. We are currently engaged in negotiations with financial advisors for the noteholderscertain holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes, and havenotes. To the extent the restructuring efforts result in an interest payment obligation under our 2022 Notesexchange of approximately $29 million, due on May 16, 2016. We are alsodebt for equity, it may result in discussions with our banks regarding an amendment to our bank credit facility. See "Liquidity and Capital Resources". Additionally, as part of this restructuring process, we are in discussions with certain vendors with whom we have significant contractual obligations.dilution for the existing stockholders. We cannot provide any assurances that we will be able to complete a private restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness.
Known Trends and Uncertainties
Declining Commodity Prices – We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016. Additionally, the low commodity prices have adversely affected the estimated value and quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties. For the years ended December 31, 2014 and 2015 and the first quarterand second quarters of 2016, we recognized ceiling test write-downs of our oil and gas properties of $351 million, $1,362 million, $129 million and $129$119 million, respectively. If NYMEX commodity prices remain at current levels (approximately $45$44 per Bbl of oil and $1.88$2.90 per MMBtu of natural gas), we would expect only minimal downward revisions of our estimated proved reserve quantities and would expect to recognize an additional ceiling test write-down between $75$0 and $175$100 million in the secondthird quarter of 2016.
Bank Credit Facility The level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. On June 14, 2016, we entered into the Amendment to the bank credit facility to, among other things, increase the borrowing base to $360 million from $300 million and revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to1 for the fiscal quarter ending September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter. See "Liquidity and Capital Resources". We were in compliance with all of our financial covenants under ourthe bank credit facility and the indentures governing our outstanding notes as of March 31,June 30, 2016. However, givenwe anticipate that the lower commodity pricesminimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our reduced hedged positioninterest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we willcould exceed the Consolidated Funded Debt to consolidated EBITDALeverage financial covenant of 3.75 to 1 set forth in our bank credit facility at the end of the secondfirst quarter of 2016, which would require us to seek2017, when the relaxed covenant levels end, unless a waivermaterial portion of our debt is repaid, reduced or amendment from our bank lenders.exchanged into equity. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.
Additionally, the significant decline in commodity prices has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. On April 13, 2016, theThe borrowing base under our bank credit facility as of August 2, 2016 was reduced$360 million, a reduction from the borrowing base of $500 million to $300 million, resulting in a $175.3 million borrowing base deficiency.as of April 12, 2016. See "Liquidity and Capital Resources". Continued low commodity prices or further declines in commodity prices could have a further adverse impact on

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the estimated value and quantities of our proved reserves and could result in additional reductions of our borrowing base under our bank credit facility.
BOEM BondingFinancial Assurance Requirements – The BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we and many other operators have been able to obtain an exemption from most bonding obligations based on financial net worth. However, in September 2015, the BOEM issued draft guidance (the “Draft Guidance”) describing revised financial assurance requirements that the agency intends to begin imposing in 2016.  Once the Draft Guidance is finalized, the BOEM will issue these supplemental bonding changes in a revised Notice to Lessees (“NTL”) in replacement of an existing NTL on supplemental bonding that was made effective on August 28, 2008.  Among other things, the Draft Guidance proposes to eliminate the “waiver” exemption currently allowed by BOEM, whereby certain operators on the Outer Continental Shelf projecting a relatively large net worth and meeting certain other criteria have the option of being exempted from posting bonds or other acceptable assurances for such operator's decommissioning obligations. Currently, qualifying operators may self-insure to meet supplemental bonding requirements, but only so long as the cumulative decommissioning liability amount being self-insured by

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the operator is no more than 50% of the operator's net worth.  Under the Draft Guidance, this waiver option would be eliminated and operators would only be able to self-insure for an amount that is no more than 10% of their tangible net worth.
On March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s current guidance to lessees.lessees at that time. BOEM's notice letters indicateindicated the amount of Stone's supplemental bonding needs could be as much as $565 million. However, we are in discussions with BOEM to reduce the amount of the supplemental bonding or other forms of financial assurance that the agency may require and the timing of when such bonds or financial assurances may need to be provided. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which remains subjectprovides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to approval by BOEM.make progress with BOEM in finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $223$230 million posted in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations.
We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed tailored plan provides for posting somewould require approximately $16 million of incremental financial assurances, and discussions onassurance or bonding for 2016, a majority of which may require cash collateral. Under the approval and implementation ofsubmitted plan, additional financial assurance would be required for subsequent years. There is no assurance this plan are continuing with BOEM. We cannot provide assurance that our proposedtailored plan will be acceptableapproved by BOEM. Additionally, on July 14, 2016, BOEM issued a new NTL that augments requirements for the posting of additional financial assurance by offshore lessees. We are reviewing the new NTL and its potential impact to BOEM. Moreover, BOEM’s Draft GuidanceStone.
The new NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS,outer continental shelf ("OCS"), which will in turn force these operators to seek additional surety bonds and could, consequently, exceed the surety bond market’s current capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety may have about the priority of their lien on the operator's collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.
In addition, although the surety companies have not historically required collateral from us to back our surety bonds, we have recently provided some cash collateral will be required on a portion of our existing surety bonds as well asand may be required to provide cash collateral on additional surety bonds we expect will be required to satisfy BOEM's financial assurance requirements.We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds to comply with supplemental bonding requirements of the BOEM. This need to obtain additional surety bonds, or some other form of financial assurances, could impact our liquidity. 
Hurricanes – Since a large portion of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable and practical insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time so we have eliminated our hurricane insurance coverage. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible increases to and/or acceleration of plugging and abandonment costs.costs, all of which could also affect our ability to remain in compliance with the covenants under our bank credit facility.
Deep Water Operations – We are currently operating two significant properties in the deep water of the GOM. Additionally, we are engagedGOM and engage in deep water drilling operations. Operations in the deep water can result in increasedinvolve high operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010.risks. Despite technological advances since this disaster,over the last several years, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant losses on our statement of operations as well as going concern issues.
Liquidity and Capital Resources
Overview.
On April 13, 2016, ourthe borrowing base under theour bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. Our agreement withAt the banks provides that within 30 days after notificationtime, we elected to pay the deficiency in six equal monthly installments, making the first two payments of a$29.2 million in May and June 2016. On June 14, 2016, we entered into the Amendment to the bank credit facility to, among other things, increase the borrowing base deficiency,to $360 million, and on that date, we must elect to curerepaid $56.8 million in borrowings, which eliminated the borrowing base deficiency through any combinationand brought the total borrowings and letters of certain actions, describedcredit outstanding under the bank credit facility in more detail below underconformity with the borrowing base limitation. See "Bank Credit Facility".Facility" Additionally,below. As of August 2, 2016, we had $341.5 million of outstanding borrowings and $18.3 million of outstanding letters of credit, leaving approximately $0.2 million of availability under the bank credit facility. We have $300 million of 2017 Convertible Notes that we need to restructure or repay by March 1, 2017 and we have an interest payment obligation under our 2022 Notes of approximately $29 million, due on May 16, 2016 (see "Senior Notes" below). As of May 4,August 2, 2016, we had cash on hand of approximately $350$165.5 million.

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Our capital expenditure budget for 2016 has beenwas set by the board of directors at $200 million, which assumesand assumed success in farming out the ENSCO 8503 deep water drilling rig to other operators for five to six months and the reduction in our working interests to acceptable levels on potential exploration wells to be drilled, or if unsuccessful, stacking the rig. The farm out subsidies and rig stacking expenses would be charges to our statement of operations as "Other operational expenses" and couldare expected to range between $40 million and $50 million. In early FebruaryDuring the first two quarters of 2016, we successfully executed onetwo separate rig farm out arrangementarrangements for the ENSCO 8503 with another operator.other operators. On June 24, 2016, our contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. Further, we agreed to provide Ensco the opportunity to perform certain drilling services commenced before December 31, 2019, and paid Ensco a $5 million deposit to be used against future drilling activities initiated before March 31, 2017, subject to extension in certain circumstances. The farm out endedENSCO 8503 deep water drilling rig contract included an operating day rate of $341,000 and was scheduled to expire in mid-April of 2016. We are working towards an agreement on a second farm out arrangement that is expected to commence prior to May 15, and continue discussions with other potential farm out and farm in partners.August 2017. To further reduce capital expenditures for 2016, we have elected to suspendtemporarily stack the Pompano platform drilling program after the completion of the initial development well, which is expectedrig in place. We currently expect to be completedreinstate drilling operations in early May of 2016. Additionally, if we2017. The updated rig schedule and cost reduction efforts have not secured partners for the Lamprey, Derbio or Rampart exploration wells, operations of the ENSCO 8503decreased our projected 2016 capital expenditures to approximately $160 million to $170 million, excluding any deep water exploration drilling rig are expected to be suspended in the third quarterand fourth quarters of 2016, following the completion of the second farm out.2016. The 2016 capital expenditure budget excludes material acquisitions and capitalized salaries, general

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and administrative (“SG&A”) expenses and interest as well as potential subsidy expense associated with rig farm outs, and rig stacking charges.charges and termination consideration.

Also, in late June 2016, Stone entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia. The interim agreement provides near-term relief for Stone by permitting Stone to resume profitable production and positive cash flow at the Mary field. The initial term of the interim agreement is through August 31, 2016 and it continues on a month to month basis thereafter unless terminated by either party. Subsequent to the execution of the interim agreement, production from much of the Mary field resumed in late June and averaged over 75 MMcfe per day in July, with total Appalachia volumes averaging 95 MMcfe per day in July. We expect daily production rates from Appalachia to reach over 125 MMcfe per day in the third quarter of 2016, resulting in increased cash flow along with increases in lease operating and transportation, processing and gathering expenses.
Based on our current outlook of commodity prices and our estimated production for 2016, we expect to fund our 2016 capital expenditures primarily with cash on hand from borrowings under our bank credit facility and expected cash flows from operating activities, as well as possible financings or asset sales. If we fall out of compliance with the covenants set forth in our bank credit facility at the end of the second quarter of 2016 and are unable to reach an agreement with our banks, find acceptable alternative financing or complete asset sales, then we may need to adjust our capital expenditure budget. In order to address the March 2017 maturity of our 2017 Convertible Notes, we continue to analyze a variety of financing options, including a restructuring with current holders of the 2017 Convertible Notes (which may include exchanges of our 2017 Convertible Notes for new debt and/or equity securities), securing a secondary credit facility or second lien notes, utilizing the current credit facility, sale or joint venture of core or non-core assets, a sale and leaseback of owned infrastructure and issuance of debt or equity in the public or private markets. Such transactions, if any, will depend on prevailing market conditions, contractual restrictions and other factors, some of which may be outside of our control. Current market conditions may put limitations on our ability to issue new debt or equity securities in the public or private markets. The ability of oil and gas companies to access the equity and high yield debt markets has been significantly limited since the significant decline in commodity prices throughout 2015 and into 2016.
Historically, we have been able to obtain an exemption from supplemental bonding requirements on our offshore leases for abandonment obligations based on financial net worth, however, on March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s current guidance to lessees. BOEM's notice letters indicate the amount of Stone's supplemental bonding needs could be as much as $565 million. We are in discussions with BOEM to reduce the amount of the supplemental bonding or other forms of financial assurancelessees at that the agency may require and the timing of when such bonds or financial assurances may need to be provided.time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which remains subject to approval by BOEM. We currently have approximately $223 million posted in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations.Our proposed tailored plan provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and discussionsimplementing our long-term tailored plan. We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed plan would require approximately $16 million of incremental financial assurance or bonding for 2016, a majority of which may require cash collateral. Under the submitted plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Additionally, on July 14, 2016, BOEM issued a new NTL that augments requirements for the approvalposting of additional financial assurances by offshore lessees. We are reviewing the new NTL and implementation of this plan are ongoing. its potential impact to Stone.
Although the surety companies have not historically required collateral from us to back our surety bonds, we have recently provided some cash collateral will be required on a portion of our existing surety bonds as well asand may be required to provide cash collateral on additional surety bonds we expect will be required to satisfy BOEM's financial assurance requirements. This need to obtain additional surety bonds or some other form of financial assurance, could impact our liquidity. See Known Trends and Uncertainties.
Indebtedness.
Bank Credit Facility – On June 24, 2014, we entered into an amended and restateda revolving credit facility with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019 and is guaranteed by our Guarantor Subsidiaries. The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing

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base redetermined. On April 13, 2016, we received notice that our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. We have not taken any action or made an electionAt that time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of actions$29.2 million in May and June 2016.
On June 14, 2016, we entered into the Amendment to be takenthe bank credit facility to cure(i) increase the borrowing base deficiency.to $360 million from $300 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ending September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the Amendment) of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures from June through December 2016, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50.0 million to apply after December 10, 2016. Upon execution of the Amendment, we repaid $56.8 million in borrowings under the credit facility, bringing total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation. On August 2, 2016, we had $341.5 million of outstanding borrowings and $18.3 million of outstanding letters of credit, leaving $0.2 million of availability under the bank credit facility.

The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage and grant a security interest in our oil and natural gas reserves representing at least 80%86% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Low commodity prices and negative price differentials have had a material adverse impact on the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. Continued low commodity prices or further declines in commodity prices will likely have a further material adverse impact on the value of our estimated proved reserves.

Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. UnderIn addition to the financial covenants of ourdiscussed above, the bank credit facility provides that we must (1) maintain a ratio of Consolidated Funded Debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.75 to 1 and (2) maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 2.502.5 to

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1. In addition, ourThe bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.

As of March 31,June 30, 2016, we were in compliance with all of our financial covenants under ourthe bank credit facility and the indentures governing our outstanding notes. However, givenwe anticipate that the lower commodity pricesminimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our reduced hedged positioninterest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we willcould exceed the Consolidated Funded Debt to consolidated EBITDALeverage financial covenant of 3.75 to 1 set forth in our bank credit facility at the end of the secondfirst quarter of 2016, which would require us to seek2017, when the relaxed covenant levels end, unless a waivermaterial portion of our debt is repaid, reduced or amendment from our bank lenders. We are currently in discussions with our banks regarding an amendment to our bank credit facility. exchanged into equity. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.
Senior Notes – Our senior notes consist of $300 million of 2017 Convertible Notes and $775 million of 2022 Notes. The 2017 Convertible Notes will be due on March 1, 2017, unless earlier converted or repurchased by us at the option of the holder(s). We are actively analyzing a variety of financing options to address the March 2017 maturity of our 2017 Convertible Notes.Notes (see Overview). We have an interest payment obligation under our 2017 Convertible Notes of approximately $2.6 million, due on September 1, 2016, and one under our 2022 Notes of approximately $29$29.2 million, due on May 16,November 15, 2016.The indenture governing the 2022 Notes provides a 30-day grace period that extends the latest date for making this cash interest payment to June 14, 2016 before an Event of Default occurs under the indenture, which would give the trustee or the holders of at least 25% in principal amount of the 2022 Notes the option to accelerate payment of the principal plus accrued and unpaid interest on the 2022 Notes. Although we have sufficient liquidity to make the interest payment by the due date, we may, alternatively, utilize the 30-day grace period provided for by the indenture, to allow us additional time to assess our restructuring alternatives.
Cash Flow and Working Capital.
Net cash (used in) provided by operating activities totaled $29.4($2.1) million during the threesix months ended March 31,June 30, 2016 compared to $83.5$145.7 million during the comparable period in 2015. The decrease was primarily due to the decline in our hedge-effected oil, natural gas and NGL prices, and the decline in natural gas and NGL production volumes, restructuring fees, rig subsidy and stacking expenses and the ENSCO 8503 termination fee, partially offset by a decline in lease operating and transportation, processing and gathering and SG&A expenses. See "Results of Operations" for additional information relative to commodity prices, production and operating expense variances.

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Net cash used in investing activities totaled $129.3$179.2 million during the threesix months ended March 31,June 30, 2016, which primarily represents our investment in oil and gas properties. Net cash provided byused in investing activities totaled $7.1$75.5 million during the threesix months ended March 31,June 30, 2015, which primarily represents our investment in oil and gas properties of $169.9$264.4 million, offset by $177.6$179.5 million of previously restricted proceeds from the sale of oil and gas properties.
Net cash provided by financing activities totaled $456.3$339.7 million during the threesix months ended March 31,June 30, 2016, which primarily represents $477.0 million of borrowings under our bank credit facility less $20.0$135.5 million in repayments of borrowings under our bank credit facility. Net cash used in financing activities totaled $3.0$3.1 million during the threesix months ended March 31,June 30, 2015, which primarily represents net payments for share-based compensation. During the threesix months ended March 31,June 30, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility.
We had a working capital deficit at March 31,June 30, 2016 of $87.5 million.$123.0 million, which included $288.3 million related to the 2017 Convertible Notes due on March 1, 2017.
Capital Expenditures.
During the three months ended March 31,June 30, 2016, additions to oil and gas property costs of $87.3$40.2 million included $0.6$0.7 million of lease and property acquisition costs, $5.8$6.6 million of capitalized SG&A expenses (inclusive of incentive compensation) and $7.4$6.9 million of capitalized interest. During the six months ended June 30, 2016, additions to oil and gas property costs of $127.5 million included $1.3 million of lease and property acquisition costs, $12.4 million of capitalized SG&A expenses (inclusive of incentive compensation) and $14.3 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities.
Contractual Obligations and Other Commitments
We have various contractual obligations and other commitments in the normal course of operations. For further information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Other Commitments” in our 2015 Annual Report on Form 10-K. ThereOn October 6, 2014, we entered into an agreement to contract the ENSCO 8503 deep water drilling rig for our multi-year deep water drilling program in the GOM. On June 24, 2016, our contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. Further, we agreed to provide Ensco the opportunity to perform certain drilling services commenced before December 31, 2019, and paid Ensco a $5 million deposit to be used against future drilling activities initiated before March 31, 2017, subject to extension in certain circumstances. The ENSCO 8503 deep water rig contract included an operating day rate of $341,000 and was scheduled to expire in August 2017. Other than the termination of the Ensco contract, there have been no material changes to this disclosure during the threesix months ended March 31,June 30, 2016.

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Results of Operations
The following table sets forth certain information with respect to our oil and gas operations:
Three Months Ended
March 31,
    Three Months Ended
June 30,
    
2016 2015 Variance % Change2016 2015 Variance % Change
Production:              
Oil (MBbls)1,635
 1,622
 13
 1 %1,548
 1,534
 14
 1 %
Natural gas (MMcf)6,846
 11,157
 (4,311) (39)%5,100
 12,581
 (7,481) (59)%
NGLs (MBbls)364
 683
 (319) (47)%244
 794
 (550) (69)%
Oil, natural gas and NGLs (MBoe)3,140
 4,165
 (1,025) (25)%2,642
 4,425
 (1,783) (40)%
Oil, natural gas and NGLs (MMcfe)18,840
 24,987
 (6,147) (25)%15,852
 26,549
 (10,697) (40)%
Revenue data (in thousands): (1)
              
Oil revenue$60,275
 $107,507
 $(47,232) (44)%$72,711
 $111,585
 $(38,874) (35)%
Natural gas revenue15,173
 28,337
 (13,164) (46)%12,553
 26,907
 (14,354) (53)%
NGLs revenue4,735
 12,366
 (7,631) (62)%3,718
 11,033
 (7,315) (66)%
Total oil, natural gas and NGL revenue$80,183
 $148,210
 $(68,027) (46)%$88,982
 $149,525
 $(60,543) (40)%
Average prices:              
Prior to the cash settlement of effective hedging contracts              
Oil (per Bbl)$31.22
 $45.31
 $(14.09) (31)%$43.66
 $55.55
 $(11.89) (21)%
Natural gas (per Mcf)1.70
 2.29
 (0.59) (26)%1.72
 1.82
 (0.10) (5)%
NGLs (per Bbl)13.01
 18.11
 (5.10) (28)%15.24
 13.90
 1.34
 10 %
Oil, natural gas and NGLs (per Boe)21.47
 26.76
 (5.29) (20)%30.31
 26.93
 3.38
 13 %
Oil, natural gas and NGLs (per Mcfe)3.58
 4.46
 (0.88) (20)%5.05
 4.49
 0.56
 12 %
Including the cash settlement of effective hedging contracts              
Oil (per Bbl)$36.87
 $66.28
 $(29.41) (44)%$46.97
 $72.74
 $(25.77) (35)%
Natural gas (per Mcf)2.22
 2.54
 (0.32) (13)%2.46
 2.14
 0.32
 15 %
NGLs (per Bbl)13.01
 18.11
 (5.10) (28)%15.24
 13.90
 1.34
 10 %
Oil, natural gas and NGLs (per Boe)25.54
 35.58
 (10.04) (28)%33.68
 33.79
 (0.11)  %
Oil, natural gas and NGLs (per Mcfe)4.26
 5.93
 (1.67) (28)%5.61
 5.63
 (0.02)  %
Expenses (per Mcfe):              
Lease operating expenses$1.04
 $1.10
 $(0.06) (5)%$1.19
 $1.03
 $0.16
 16 %
Transportation, processing and gathering expenses0.04
 0.71
 (0.67) (94)%0.45
 0.75
 (0.30) (40)%
SG&A expenses (2)0.73
 0.68
 0.05
 7 %1.26
 0.62
 0.64
 103 %
DD&A expense on oil and gas properties3.21
 3.41
 (0.20) (6)%2.85
 2.89
 (0.04) (1)%
 
(1)Includes the cash settlement of effective hedging contracts.
(2)Excludes incentive compensation expense.





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 Six Months Ended
June 30,
    
 2016 2015 Variance % Change
Production:       
Oil (MBbls)3,183
 3,156
 27
 1 %
Natural gas (MMcf)11,946
 23,738
 (11,792) (50)%
NGLs (MBbls)608
 1,477
 (869) (59)%
Oil, natural gas and NGLs (MBoe)5,782
 8,589
 (2,807) (33)%
Oil, natural gas and NGLs (MMcfe)34,692
 51,536
 (16,844) (33)%
Revenue data (in thousands): (1)
       
Oil revenue$132,986
 $219,092
 $(86,106) (39)%
Natural gas revenue27,726
 55,244
 (27,518) (50)%
NGLs revenue8,453
 23,399
 (14,946) (64)%
Total oil, natural gas and NGL revenue$169,165
 $297,735
 $(128,570) (43)%
Average prices:       
Prior to the cash settlement of effective hedging contracts       
Oil (per Bbl)$37.27
 $50.28
 $(13.01) (26)%
Natural gas (per Mcf)1.71
 2.04
 (0.33) (16)%
NGLs (per Bbl)13.90
 15.84
 (1.94) (12)%
Oil, natural gas and NGLs (per Boe)25.51
 26.85
 (1.34) (5)%
Oil, natural gas and NGLs (per Mcfe)4.25
 4.47
 (0.22) (5)%
Including the cash settlement of effective hedging contracts       
Oil (per Bbl)$41.78
 $69.42
 $(27.64) (40)%
Natural gas (per Mcf)2.32
 2.33
 (0.01)  %
NGLs (per Bbl)13.90
 15.84
 (1.94) (12)%
Oil, natural gas and NGLs (per Boe)29.26
 34.66
 (5.40) (16)%
Oil, natural gas and NGLs (per Mcfe)4.88
 5.78
 (0.90) (16)%
Expenses (per Mcfe):       
Lease operating expenses$1.11
 $1.07
 $0.04
 4 %
Transportation, processing and gathering expenses0.23
 0.73
 (0.50) (68)%
SG&A expenses (2)0.94
 0.65
 0.29
 45 %
DD&A expense on oil and gas properties3.04
 3.14
 (0.10) (3)%
(1)Includes the cash settlement of effective hedging contracts.
(2)Excludes incentive compensation expense.    

Net Loss. During the three months ended March 31,June 30, 2016, we reported a net loss totaling approximately $188.8$195.8 million, or $3.39$35.05 per share, compared to a net loss for the three months ended March 31,June 30, 2015 of $327.4$152.9 million, or $5.93$27.68 per share. During the six months ended June 30, 2016, we reported a net loss totaling approximately $384.5 million, or $68.94 per share, compared to a net loss for the six months ended June 30, 2015 of $480.3 million, or $86.99 per share. All per share amounts are on a diluted basis.
We follow the full cost method of accounting for oil and gas properties. During the three months ended June 30, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $118.6 million and $224.3 million, respectively. During the three months ended March 31, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $128.9 million and $491.4 million, respectively. During the three months ended March 31, 2016, we recognized a ceiling test write-down of our Canadian oil and gas properties, which were deemed fully impaired at the end of 2015, totaling $0.3 million. The write-downs did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity.
The variance in the three and six month periods’ results was also due to the following components:
Production. During the three months ended March 31,June 30, 2016, total production volumes decreased to 18.815.9 Bcfe compared to 25.026.5 Bcfe produced during the comparable 2015 period, representing a 25%40% decrease. Oil production during the three months ended March 31,June 30, 2016 totaled approximately 1,6351,548 MBbls compared to 1,6221,534 MBbls produced during the comparable 2015 period. Natural gas production totaled 6.85.1 Bcf during the three months ended March 31,June 30, 2016 compared to 11.212.6 Bcf during the comparable 2015 period. NGL production during the three months ended March 31,June 30, 2016 totaled approximately 364244 MBbls compared to 683794 MBbls produced during the comparable

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2015 period. The decreases in natural gas and NGL production volumes during the three months ended June 30, 2016 were primarily attributable to the shut-in of production at our Mary field sincefrom September 2015.2015 until late June 2016.
During the six months ended June 30, 2016, total production volumes decreased to 34.7 Bcfe compared to 51.5 Bcfe produced during the comparable 2015 period, representing a 33% decrease. Oil production during the six months ended June 30, 2016 totaled approximately 3,183 MBbls compared to 3,156 MBbls produced during the comparable 2015 period. Natural gas production totaled 11.9 Bcf during the six months ended June 30, 2016 compared to 23.7 Bcf during the comparable 2015 period. NGL production during the six months ended June 30, 2016 totaled approximately 608 MBbls compared to 1,477 MBbls produced during the comparable 2015 period. The decreases in natural gas and NGL production volumes during the six months ended June 30, 2016 were primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016.
Prices. Prices realized during the three months ended March 31,June 30, 2016 averaged $36.87$46.97 per Bbl of oil, $2.22$2.46 per Mcf of natural gas and $13.01$15.24 per Bbl of NGLs, compared to average realized prices of $72.74 per Bbl of oil, $2.14 per Mcf of natural gas and $13.90 per Bbl of NGLs during the comparable 2015 period. Prices realized during the six months ended June 30, 2016 averaged $41.78 per Bbl of oil, $2.32 per Mcf of natural gas and $13.90 per Bbl of NGLs, or 28%16% lower, on an Mcfe basis, than average realized prices of $66.28$69.42 per Bbl of oil, $2.54$2.33 per Mcf of natural gas and $18.11$15.84 per Bbl of NGLs during the comparable 2015 period. All unit pricing amounts include the cash settlement of effective hedging contracts.
We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. Our effective hedging transactions increased our average realized natural gas price by $0.52$0.74 per Mcf and increased our average realized oil price by $5.65$3.31 per Bbl during the three months ended March 31,June 30, 2016. During the three months ended March 31,June 30, 2015, our effective hedging transactions increased our average realized natural gas price by $0.25$0.32 per Mcf and increased our average realized oil price by $20.97$17.19 per Bbl. During the six months ended June 30, 2016, our effective hedging transactions increased our average realized natural gas price by $0.61 per Mcf and increased our average realized oil price by $4.51 per Bbl. During the six months ended June 30, 2015, our effective hedging transactions increased our average realized natural gas price by $0.29 per Mcf and increased our average realized oil price by $19.14 per Bbl.
Revenue. Oil, natural gas and NGL revenue was $80.2$89.0 million during the three months ended March 31,June 30, 2016 compared to $148.2$149.5 million during the comparable period of 2015. For the six months ended June 30, 2016 and 2015, oil, natural gas and NGL revenue totaled $169.2 million and $297.7 million, respectively. The decrease in total revenue for the three months ended June 30, 2016 was primarily due to a 40% decrease in production volumes and a 35% decrease in average realized oil prices from the comparable period of 2015. The decrease in total revenue for the threesix months ended March 31,June 30, 2016 was primarily due to a 28%33% decrease in production volumes and a 16% decrease in average realized prices and a 25% decrease in production volumeson an equivalent basis from the comparable period of 2015.
Derivative Income.Income/Expense. Net derivative incomeexpense for the three months ended March 31,June 30, 2016 totaled $0.1$0.6 million, comprised of $0.3$0.2 million of income from cash settlements and $0.2$0.8 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the three months ended March 31,June 30, 2015, net derivative incomeexpense totaled $3.1$0.7 million, comprised of $4.6$5.7 million of income from cash settlements and $1.5$6.4 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. Net derivative expense for the six months ended June 30, 2016 totaled $0.5 million, comprised of $0.5 million of income from cash settlements and $1.0 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the six months ended June 30, 2015, net derivative income totaled $2.4 million, comprised of $10.3 million of income from cash settlements and $7.9 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.
Expenses. Lease operating expenses during the three months ended March 31,June 30, 2016 and 2015 totaled $19.5$18.8 million and $27.6$27.4 million, respectively. On a unit of production basis,For the six months ended June 30, 2016 and 2015, lease operating expenses were $1.04 per Mcfetotaled $38.4 million and $1.10 per Mcfe for the three months ended March 31, 2016 and 2015,$55.0 million, respectively. The decrease in lease operating expenses during the three and six months ended March 31,June 30, 2016 was primarily attributable to service cost reductions, the implementation of cost-savings measures, operating efficiencies and the shut-in of production at our Mary field sincefrom September 2015.2015 until late June 2016. On a unit of production basis, lease operating expenses were $1.19 per Mcfe and $1.03 per Mcfe for the three months ended June 30, 2016 and 2015, respectively, and $1.11 per Mcfe and $1.07 per Mcfe for the six months ended June 30, 2016 and 2015, respectively. The unit cost of lease operating expenses increased during the three and six months ended June 30, 2016 from the comparable periods of 2015 as a result of decreased production volumes from Appalachia.
Transportation, processing and gathering expenses during the three months ended March 31,June 30, 2016 and 2015 totaled $0.8$7.2 million and $17.7$19.9 million, respectively, or $0.04$0.45 per Mcfe and $0.71$0.75 per Mcfe, respectively. For the six months ended June 30, 2016 and 2015, transportation, processing and gathering expenses totaled $8.0 million and $37.6 million, respectively, or $0.23 per Mcfe and $0.73 per Mcfe, respectively. The decrease was attributable to the shut-in of production at our Mary field sincefrom September 2015 until late June 2016 as well as the recoupment of previously paid transportation costs allocable to the Federal government's portion of certain of our deep water production, which amounted to approximately $4 million.
Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the three months ended March 31,June 30, 2016 totaled $60.4$45.1 million compared to $85.2$76.8 million during the comparable period of 2015. For the six months ended June 30, 2016 and 2015, DD&A expense totaled $105.6 million and $162.0 million, respectively. On a unit of production basis, DD&A expense was $3.21 $2.85

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per Mcfe and $3.41$2.89 per Mcfe during the three months ended March 31,June 30, 2016 and 2015, respectively. For the six months ended June 30, 2016 and 2015, DD&A expense, on a unit of production basis, was $3.04 per Mcfe and $3.14 per Mcfe, respectively. The decrease in DD&A during the three and six months ended March 31,June 30, 2016 was primarily due to the ceiling test write-downs of our oil and gas properties.
Other operational expenses for the three months ended March 31,June 30, 2016 and 2015 totaled $12.5$27.7 million and $0.1$1.5 million, respectively. Included in other operational expenses for the three months ended March 31,June 30, 2016 is a $20 million charge related to the termination of our deep water drilling rig contract with Ensco and approximately $7.5 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and the platform rig at Pompano. For the six months ended June 30, 2016 and 2015, other operational expenses totaled $40.2 million and $1.2 million, respectively. Included in other operational expenses for the six months ended June 30, 2016 is the $20 million Ensco contract termination charge, approximately $13.6 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and the platform rig at Pompano and a $6.0 million cumulative foreign currency translation loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments which werewas reclassified from accumulated other comprehensive income. Also included in other operational expenses for the three months ended March 31, 2016 are approximately $6.1 million of rig subsidy charges related to the farm out of the ENSCO 8503 deep water drilling rig and stacking charges related to the Saxon Appalachian rig.
SG&A expenses (exclusive of incentive compensation) for the three months ended March 31,June 30, 2016 were $13.7$20.0 million compared to $17.0$16.4 million for the three months ended March 31,June 30, 2015. For the six months ended June 30, 2016 and 2015, SG&A expenses (exclusive of incentive compensation) totaled $32.8 million and $33.4 million, respectively. On a unit of production basis, SG&A expenses were $0.73$1.26 per Mcfe and $0.68$0.62 per Mcfe for the three months ended March 31,June 30, 2016 and 2015, respectively. For the six months ended June 30, 2016 and 2015, SG&A expenses, on a unit of production basis, were $0.94 per Mcfe and $0.65 per Mcfe, respectively. The decreaseincrease in SG&A expenses for the three months ended March 31,June 30, 2016 relatedwas primarily attributable to legal fees pertaining to Stone's pursuit of a reduction of our workforce. SG&A expensesclaim for damages against a third party, partially offset by staff and other cost reductions.
For the three and six months ended March 31,June 30, 2016, included approximately $1restructuring fees totaled $9.4 million of professionaland $10.4 million, respectively. These fees associated withrelated to expenses supporting a restructuring effort including legal and financial advisory costs for Stone, our debt restructuring efforts.bank group and our noteholders.
For the three months ended March 31,June 30, 2016 and 2015, incentive compensation expense totaled $5.0$4.7 million and $1.6$1.3 million, respectively. These amounts related toFor the accrual of estimatedsix months ended June 30, 2016 and 2015, incentive compensation expense totaled $9.6 million and $2.8 million, respectively. The 2016 incentive compensation cash bonuses which are calculated based on the projected achievement of certain strategic objectives for each fiscal year.quarter of 2016. Portions of the 2016 incentive cash bonuses replace amounts previously awarded to employees as stock-based compensation, reflected in SG&A expenses, resulting in higher incentive compensation expense in the 2016 periods as compared to the 2015 periods. 
Interest expense for the three months ended March 31,June 30, 2016 totaled $15.2$17.6 million, net of $7.4$6.9 million of capitalized interest, compared to interest expense of $10.4$10.5 million, net of $10.8 million of capitalized interest, during the comparable 2015 period. For the six months ended June 30, 2016, interest expense totaled $32.8 million, net of $14.3 million of capitalized interest, compared to interest expense of $20.8 million, net of $21.6 million of capitalized interest, during the comparable 2015 period. The increase in interest expense was primarily the result of interest expense associated with the increased borrowings under our bank credit facility and a decrease in the amount of interest capitalized to oil and gas properties and interest expense associated with the increased borrowings under our bank credit facility.

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properties.
For the threesix months ended March 31,June 30, 2016 and 2015, we recorded an income tax provision (benefit) of $1.8$5.9 million and ($179.9)265.0) million, respectively. The income tax benefit recorded for the threesix months ended March 31,June 30, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs of our oil and gas properties. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined in the third quarter of 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. The change in the valuation allowance was recorded as an adjustment to income tax expense.
Off-Balance Sheet Arrangements
None.
Recent Accounting Developments
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements.

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In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.
Defined Terms
Oil, condensate and NGLs are stated in barrels (“Bbls”) or thousand barrels (“MBbls”). Natural gas is stated in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). Oil, condensate and NGLs are converted to natural gas at a ratio of one barrel of liquids per six Mcf of gas. Bcfe, MMcfe and Mcfe represent one billion cubic feet, one million cubic feet and one thousand cubic feet of gas equivalent, respectively. MMBoe and MBoe represent one million and one thousand barrels of oil equivalent, respectively. MMBtu represents one million British Thermal Units. An active property is an oil and gas property with existing production. A primary term lease is an oil and gas property with no existing production, in which we have a specific time frame to establish production without losing the rights to explore the property. Liquidity is defined as the ability to obtain cash quickly either through the conversion of assets or incurrence of liabilities.


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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. For the threesix months ended March 31,June 30, 2016, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $4.8$11.4 million impact on our revenues. Excluding the effects of hedging contracts, a 10% fluctuation in realized oil and natural gas prices would have had an approximate $6.7$14.7 million impact on our revenues. In order to manage our exposure to oil and natural gas price declines, we enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.
Our hedging policy currently provides that not more than 60% of our estimated production quantities can be hedged for any given year without the consent of the board of directors. We believe that our hedging positions as of May 4,August 2, 2016 have hedged approximately 28% of our estimated 2016 production from estimated proved reserves. Although we continue to monitor the marketplace for additional hedges for 2016 and beyond, continued weakness in commodity prices may impair our ability to secure hedges at prices we deem acceptable. See Part I, Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities, of this Form 10-Q for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.
Since the filing of our 2015 Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to commodity prices.
Interest Rate Risk
We had total debt outstanding of $1,544$1,428 million at March 31,June 30, 2016, of which $1,087 million, or 70%76%, bears interest at fixed rates. The $1,087 million of fixed-rate debt is comprised of $300 million of the 2017 Convertible Notes, $775 million of the 2022 Notes and $12 million of the Building Loan. At March 31,June 30, 2016, the remaining $457$342 million of our outstanding debt bears interest at an adjustable interest rate and consists of borrowings outstanding under our bank credit facility. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources of this Form 10-Q. Borrowings under our bank credit facility may subject us to increased sensitivity to interest rate movements. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. At March 31,June 30, 2016, the weighted average interest rate under our bank credit facility was approximately 3.5%4.3% per annum.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31,June 30, 2016 at the reasonable assurance level.
Changes in Internal Controls Over Financial Reporting
There has not been any change in our internal control over financial reporting that occurred during the quarter ended March 31,June 30, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION
 
Item 1. Legal Proceedings
We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.
On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone, and related costs and attorney’s fees. Recently, the Louisiana Attorney General became a Plaintiff in all three Jefferson Parish cases. The Louisiana Attorney General’s intervention is not expected to affect the total damage amount sought from Stone in these cases.
In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. On November 12, 2015, the Plaquemines Parish Council passed a resolution instructing its attorneys to dismiss all 21 Coastal Zone Management suits filed by the Plaquemines Parish. To date, counsel for the Plaquemines Parish has not yet moved to dismiss the cases. On January 12, 2016, Stone moved to dismiss the action without prejudice. Plaintiff has not yet opposedprejudice on the motion.
On October 10, 2012, Stone received notice from the Bureau of Safety and Environmental Enforcement (“BSEE”) that it was initiating an enforcement proceeding with respect to an Incident of Non-Compliance observed at Stone's Vermillion Block 255 H Platform on April 19, 2012. Stone does not agree that the conditions observed were violations of applicable rules. BSEE issued a Reviewing Officer’s Final Decision dated July 9, 2013, assessing a penalty against Stone of $200,000, which was calculated as $25,000 per day for eight days of alleged improper venting of gas at the platform. On August 12, 2015, the Interior Board of Land Appeals affirmed the penalty. Stone's subsequent appeal to the Directorbasis of the Department ofresolution. On March 14, 2016, the Interior Office of Hearings and Appeals was unsuccessful.Louisiana Attorney General became a Plaintiff in the case, after which the Plaquemines Parish Council rescinded its resolution, forcing Stone paidto withdraw its motion to dismiss. The Louisiana Attorney General’s intervention is not expected to affect the $200,000 penalty on March 28, 2016 and the matter is now closed.total damage amount sought from Stone in this case.
On November 17, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. Prior to this, in September 2014, Stone had transferred ownership of the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. Reclamation of the site by Southwestern, with the participation of the PADEP and Stone, is now complete. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.
Legal proceedings are subject to substantial uncertainties concerning the outcome of material, factual, and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters.
Item 1A. Risk Factors
The following updates the Risk Factors included in our 2015 Annual Report on Form 10-K. Except as set forth below, there have been no material changes with respect to Stone’s risk factors previously reported in Part I, Item 1A, of our 2015 Annual Report on Form 10-K.
The closing market price of our common stock has recently declined significantly. On April 29 and May 17, 2016, we were notified by the New York Stock Exchange (the “NYSE”) that our common stock was not in compliance with NYSE listing standards. If we are unable to cure the stock pricemarket capitalization deficiency, our common stock could be delisted from the New York Stock Exchange (the “NYSE”)NYSE or trading could be suspended.
Our common stock is currently listed on the NYSE. In order for our common stock to continue to be listed on the NYSE, we are required to comply with various listing standards, including the maintenance of a minimum average closing price of at least $1.00 per share during a consecutive 30 trading-day period. In addition to the minimum average closing price criteria, we are considered to be below compliance if our average market capitalization over a consecutive 30 day-trading period is less than $50 million and, at the same time, our stockholders’ equity is less than $50 million.

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On April 29, 2016, we were notified by the NYSE that the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days. UnderOn May 17, 2016, we were notified by the NYSE’s rules,NYSE that our average global market capitalization had been less than $50 million over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50 million.

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On June 10, 2016, we have six months following receiptcompleted a 1-for-10 reverse stock split with respect to our common stock in order to increase the per share trading price of the notificationour common stock in order to regain compliance with the NYSE’s minimum share price requirement. We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the $1.00 per share average closing price requirement, oralthough we remain non-compliant with the $50 million average market capitalization and stockholders’ equity requirements.
On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity requirements. Althoughdeficiencies to the NYSE. After our submission of the business plan, the NYSE has 45 calendar days to review the plan to determine whether we have an opportunitymade reasonable demonstration of our ability to take actioncome into conformity with the relevant standards within the 18-month period. The NYSE will either accept the plan, at which time we would be subject to cure such a breach, ifongoing monitoring for compliance with the plan, or not accept the plan, at which time we do not succeed,would be subject to suspension and delisting proceedings. If the NYSE could commenceaccepts the plan, during the 18-month cure period, our shares of common stock would continue to be listed and traded on the NYSE.
In addition to potentially commencing suspension or delisting procedures in respect of our common stock. In addition,stock if the NYSE does not accept our business plan, our common stock could be delisted pursuant to Section 802.01 of the NYSE Listed Company Manual if the trading price of our common stock on the NYSE is abnormally low, which has generally been interpreted to mean at levels below $0.16 per share, and our common stock could also be delisted pursuant to Section 802.01 if our average market capitalization over a consecutive 30 day-trading period is less than $15 million. In these events, we would not have an opportunity to cure the stock price deficiency or market capitalization deficiency, and our shares would be delisted immediately and suspended from trading on the NYSE. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise additional necessary capital through equity or debt financing, and attract and retain personnel by means of equity compensation, would be greatly impaired. Furthermore, with respect to any suspended or delisted securities, we would expect decreases in institutional and other investor demand, analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such securities. A suspension or delisting would likely decrease the attractiveness of our common stock to investors and cause the trading volume of our common stock to decline, which could result in a further decline in the market price of our common stock.
New guidelines recently issued by the federal Bureau of Ocean Energy Management (BOEM) related to financial assurance requirements to cover decommissioning obligations for operations on the outer continental shelf may have a material adverse effect on our business, financial condition, or results of operations.
On July 14, 2016, BOEM issued a Notice to Lessees and Operators (NTL) that augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The NTL, effective September 12, 2016, does away with the agency’s past practice of waiving supplemental bonding obligations where a company could demonstrate a certain level of financial strength.  Instead, BOEM will allow companies to “self-insure,” but only up to 10% of a company’s “tangible net worth,” which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and if additional financial assurance must be provided. The NTL states that lessees may develop a “tailored plan” for posting any additional assurance that allows the lessee to phase-in any additional financial assurance required by BOEM. We intend to work with BOEM to develop a tailored plan for the provision of any new financial assurances required to be posted as a result of the new NTL. Compliance with the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, and limit activities in certain areas, or cause us to incur penalties or fines or to shut-in production at one or more of our facilities, or result in the suspension or cancellation of leases.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the three months ended March 31,June 30, 2016: 
Period
Total Number
of Shares
Purchased (1)
 
Average Price
Paid per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs (2)
 
Approximate Dollar Value of Shares that MayYet be
Purchased Under the
Plans or Programs
January 1 - January 31, 2016237,454
 $2.74
 
  
February 1 - February 29, 2016
 
 
  
March 1 - March 31, 2016
 
 
  
 237,454
 $2.74
 
 $92,928,632
Period
Total Number
of Shares
Purchased (1)
 
Average Price
Paid per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs (2)
 
Approximate Dollar Value of Shares that MayYet be
Purchased Under the
Plans or Programs
April 1 - April 30, 2016327
 $10.64
 
  
May 1 - May 31, 20163,788
 4.24
 
  
June 1 - June 30, 2016
 
 
  
 4,115
 $5.59
 
 $92,928,632

(1)Amount includes shares of our common stock withheld from employees and nonemployee directors upon the vesting of restricted stock in order to satisfy the required tax withholding obligations.
(2)There were no repurchases of our common stock under our share repurchase program during the three months ended March 31,June 30, 2016.
 

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Item 6. Exhibits
 
*3.1
 Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2015 filed August 6, 2015 (File No. 001-12074)).amended.
3.2
 Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 filed February 27, 2014 (File No. 001-12074)).
*10.1
 Amendment No. 3 to the Fourth Amended and Restated Credit Agreement among Stone Energy Corporation, certain of its subsidiaries, as guarantors, and the financial institutions party thereto, dated June 14, 2016 Performance(incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed June 14, 2016 (File No. 001-12074)).
*10.2
Second Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Compensation Plan (approved March 10, 2016)(As Amended and Restated December 17, 2015).
*31.1
 Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2
 Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1
 Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
*101.INS
 XBRL Instance Document
*101.SCH
 XBRL Taxonomy Extension Schema Document
*101.CAL
 XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF
 XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB
 XBRL Taxonomy Extension Label Linkbase Document
*101.PRE
 XBRL Taxonomy Extension Presentation Linkbase Document

*Filed or furnished herewith.
#Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
  STONE ENERGY CORPORATION
    
Date:May 5,August 3, 2016By:/s/ Kenneth H. Beer
   Kenneth H. Beer
   Executive Vice President and Chief Financial Officer
   (On behalf of the Registrant and as
   Principal Financial Officer)

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EXHIBIT INDEX
 
Exhibit
Number
 Description
*3.1
 Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2015 filed August 6, 2015 (File No. 001-12074)).amended.
3.2
 Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 filed February 27, 2014 (File No. 001-12074)).
*10.1
 Amendment No. 3 to the Fourth Amended and Restated Credit Agreement among Stone Energy Corporation, certain of its subsidiaries, as guarantors, and the financial institutions party thereto, dated June 14, 2016 Performance(incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed June 14, 2016 (File No. 001-12074)).
*10.2
Second Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Compensation Plan (approved March 10, 2016)(As Amended and Restated December 17, 2015).
*31.1
 Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2
 Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1
 Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
*101.INS
 XBRL Instance Document
*101.SCH
 XBRL Taxonomy Extension Schema Document
*101.CAL
 XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF
 XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB
 XBRL Taxonomy Extension Label Linkbase Document
*101.PRE
 XBRL Taxonomy Extension Presentation Linkbase Document

*Filed or furnished herewith.
#Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.



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