Stone Energy (SGY) 10-Q 2015 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________________ 

FORM 10-Q

__________________________________________________________ 

(Mark One)

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 1-12074

__________________________________________________________ 

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________

Delaware	72-1235413
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
625 E. Kaliste Saloom Road
Lafayette, Louisiana	70508
(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 filer	ý	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes  ¨    No  ý

As of November 3, 2015, there were 57,094,064 shares of the registrant’s common stock, par value $.01 per share, outstanding.

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheet as of September 30, 2015 and December 31, 2014	1
	Condensed Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2015 and 2014	2
	Condensed Consolidated Statement of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2015 and 2014	3
	Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	32
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 6.	Exhibits	34
	Signatures	35
	Exhibit Index	36

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)

	September 30, 2015			December 31, 2014
	(Unaudited)			(Note 1)
Assets
Current assets:
Cash and cash equivalents	$	74,474		$	74,488
Restricted cash	—			177,647
Accounts receivable	57,859			120,359
Fair value of derivative contracts	65,700			139,179
Current income tax receivable	—			7,212
Inventory	3,709			3,709
Other current assets	9,203			8,118
Total current assets	210,945			530,712
Oil and gas properties, full cost method of accounting:
Proved	9,204,693			8,817,268
Less: accumulated depreciation, depletion and amortization	(8,199,973		)	(6,970,631		)
Net proved oil and gas properties	1,004,720			1,846,637
Unevaluated	518,963			567,365
Other property and equipment, net	30,327			32,340
Fair value of derivative contracts	5,734			14,333
Other assets, net	25,623			27,224
Total assets	$	1,796,312		$	3,018,611
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	66,054		$	132,629
Undistributed oil and gas proceeds	10,461			23,232
Accrued interest	22,241			9,022
Deferred taxes	—			20,119
Asset retirement obligations	42,624			69,400
Other current liabilities	42,134			49,505
Total current liabilities	183,514			303,907
Long-term debt	1,052,183			1,041,035
Deferred taxes	—			286,343
Asset retirement obligations	243,567			247,009
Fair value of derivative contracts	172			—
Other long-term liabilities	25,347			38,714
Total liabilities	1,504,783			1,917,008
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 150,000,000 shares; issued 55,302,325 and 54,884,542 shares, respectively	553			549
Treasury stock (16,582 shares, at cost)	(860		)	(860		)
Additional paid-in capital	1,643,746			1,633,307
Accumulated deficit	(1,386,967		)	(614,708		)
Accumulated other comprehensive income	35,057			83,315
Total stockholders’ equity	291,529			1,101,603
Total liabilities and stockholders’ equity	$	1,796,312		$	3,018,611

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

1

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Operating revenue:
Oil production	$	105,013		$	123,795		$	324,105		$	404,477
Natural gas production	17,367			30,154			72,611			133,183
Natural gas liquids production	5,980			21,014			29,379			64,920
Other operational income	1,392			2,468			3,184			5,515
Derivative income, net	2,444			5,782			4,871			2,667
Total operating revenue	132,196			183,213			434,150			610,762
Operating expenses:
Lease operating expenses	24,244			43,561			79,250			139,918
Transportation, processing and gathering expenses	18,208			16,721			55,851			45,445
Production taxes	2,052			3,651			6,394			9,970
Depreciation, depletion and amortization	61,936			80,291			226,309			255,772
Write-down of oil and gas properties	295,679			47,130			1,011,385			47,130
Accretion expense	6,498			6,539			19,315			21,827
Salaries, general and administrative expenses	19,552			16,286			52,977			49,252
Incentive compensation expense	794			3,092			3,621			10,129
Other operational expenses	442			298			1,612			510
Total operating expenses	429,405			217,569			1,456,714			579,953
Income (loss) from operations	(297,209		)	(34,356		)	(1,022,564		)	30,809
Other (income) expenses:
Interest expense	10,872			10,323			31,709			28,593
Interest income	(47		)	(169		)	(235		)	(505		)
Other income	(411		)	(695		)	(1,167		)	(2,124		)
Other expense	148			95			148			274
Total other expenses	10,562			9,554			30,455			26,238
Income (loss) before income taxes	(307,771		)	(43,910		)	(1,053,019		)	4,571
Provision (benefit) for income taxes:
Deferred	(15,806		)	(14,495		)	(280,760		)	3,599
Total income taxes	(15,806		)	(14,495		)	(280,760		)	3,599
Net income (loss)	$	(291,965	)	$	(29,415	)	$	(772,259	)	$	972
Basic earnings (loss) per share	$	(5.28	)	$	(0.54	)	$	(13.98	)	$	0.02
Diluted earnings (loss) per share	$	(5.28	)	$	(0.54	)	$	(13.98	)	$	0.02
Average shares outstanding	55,282			54,866			55,238			51,998
Average shares outstanding assuming dilution	55,282			54,866			55,238			52,139

The accompanying notes are an integral part of this statement.

2

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net income (loss)	$	(291,965	)	$	(29,415	)	$	(772,259	)	$	972
Other comprehensive income (loss), net of tax effect:
Derivatives	(5,353		)	30,975			(45,691		)	14,620
Foreign currency translation	(246		)	(1,625		)	(2,567		)	(1,369		)
Comprehensive income (loss)	$	(297,564	)	$	(65	)	$	(820,517	)	$	14,223

The accompanying notes are an integral part of this statement.

3

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended September 30,
	2015			2014
Cash flows from operating activities:
Net income (loss)	$	(772,259	)	$	972
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	226,309			255,772
Write-down of oil and gas properties	1,011,385			47,130
Accretion expense	19,315			21,827
Deferred income tax (benefit) provision	(280,760		)	3,599
Settlement of asset retirement obligations	(59,826		)	(47,217		)
Non-cash stock compensation expense	9,163			8,409
Non-cash derivative (income) expense	10,854			(2,386		)
Non-cash interest expense	13,210			12,393
Change in current income taxes	7,211			(6		)
(Increase) decrease in accounts receivable	33,895			(1,805		)
Increase in other current assets	(1,090		)	(10		)
Decrease in accounts payable	(11,592		)	(3,547		)
Increase (decrease) in other current liabilities	(6,753		)	37,441
Other	(82		)	(172		)
Net cash provided by operating activities	198,980			332,400
Cash flows from investing activities:
Investment in oil and gas properties	(385,528		)	(727,488		)
Proceeds from sale of oil and gas properties, net of expenses	11,643			223,299
Investment in fixed and other assets	(1,455		)	(8,790		)
Change in restricted funds	179,475			(185,752		)
Net cash used in investing activities	(195,865		)	(698,731		)
Cash flows from financing activities:
Proceeds from bank borrowings	5,000			—
Repayment of bank borrowings	(5,000		)	—
Net proceeds from issuance of common stock	—			225,999
Deferred financing costs	—			(3,329		)
Net payments for share-based compensation	(3,127		)	(7,161		)
Net cash provided by (used in) financing activities	(3,127		)	215,509
Effect of exchange rate changes on cash	(2		)	(95		)
Net change in cash and cash equivalents	(14		)	(150,917		)
Cash and cash equivalents, beginning of period	74,488			331,224
Cash and cash equivalents, end of period	$	74,474		$	180,307

The accompanying notes are an integral part of this statement.

4

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”) and its subsidiaries as of September 30, 2015 and for the three and nine month periods ended September 30, 2015 and 2014 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, 2014 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, 2014 (our “2014 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 2014 Annual Report on Form 10-K. The results of operations for the three and nine month periods ended September 30, 2015 are not necessarily indicative of future financial results.

Note 2 – 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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands, except per share data)
Income (numerator):
Basic:
Net income (loss)	$	(291,965	)	$	(29,415	)	$	(772,259	)	$	972
Net income attributable to participating securities	—			—			—			(22		)
Net income (loss) attributable to common stock - basic	$	(291,965	)	$	(29,415	)	$	(772,259	)	$	950
Diluted:
Net income (loss)	$	(291,965	)	$	(29,415	)	$	(772,259	)	$	972
Net income attributable to participating securities	—			—			—			(22		)
Net income (loss) attributable to common stock - diluted	$	(291,965	)	$	(29,415	)	$	(772,259	)	$	950
Weighted average shares (denominator):
Weighted average shares - basic	55,282			54,866			55,238			51,998
Dilutive effect of stock options	—			—			—			53
Dilutive effect of convertible notes	—			—			—			88
Weighted average shares - diluted	55,282			54,866			55,238			52,139
Basic earnings (loss) per share	$	(5.28	)	$	(0.54	)	$	(13.98	)	$	0.02
Diluted earnings (loss) per share	$	(5.28	)	$	(0.54	)	$	(13.98	)	$	0.02

All outstanding stock options were considered antidilutive during the three and nine months ended September 30, 2015 (approximately 145,000 shares) and during the three months ended September 30, 2014 (approximately 205,000 shares) because we had a net loss for such periods. Stock options that were considered antidilutive because the exercise price of the options exceeded the average price of our common stock totaled approximately 116,000 shares during the nine months ended September 30, 2014.

During the three months ended September 30, 2015 and 2014, approximately 19,000 shares and 10,000 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock by employees and nonemployee directors. During the nine months ended September 30, 2015 and 2014, approximately 418,000 shares and 382,000 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock by employees and nonemployee directors. In May 2014, 5,750,000 shares of our common stock were issued in a public offering.

Because it is management’s stated intention to redeem the principal amount of our 1 3⁄4% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) (see Note 4 – Long-Term Debt) in cash, we have used the treasury method for determining dilution in the diluted earnings per share computation. For the three and nine months ended September 30, 2015 and the three months ended September 30, 2014, there was no dilutive effect on the diluted earnings per share computation because we had a net loss for such periods. For the three months ended June 30, 2014, the average price of our common stock exceeded the effective conversion price for

5

such notes, resulting in a dilutive effect on the diluted earnings per share computation for the nine months ended September 30, 2014. For all periods presented, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 4 – Long-Term Debt) and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in Note 4 – Long-Term Debt), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.

Note 3 – 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 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.

We have entered into fixed-price swaps and costless collars with various counterparties for a portion of our expected 2015 and 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, Barclays Bank PLC, The Bank of Nova Scotia, Bank of America and Natixis. Our oil collar contract is with The Bank of Nova Scotia.

The following tables illustrate our derivative positions for calendar years 2015 and 2016 as of November 3, 2015:

	Fixed-Price Swaps (NYMEX)
	Natural Gas		Oil
	Daily Volume (MMBtus/d)	Swap Price ($)	Daily Volume (Bbls/d)	Swap Price ($)
2015	10,000	4.005	1,000	89.00
2015	10,000	4.120	1,000	90.00
2015	10,000	4.150	1,000	90.25
2015	10,000	4.165	1,000	90.40
2015	10,000	4.220	1,000	91.05
2015	10,000	4.255	1,000	93.28
2015			1,000	93.37
2015			1,000	94.85
2015			1,000	95.00
2016	10,000	4.110	1,000	49.75
2016	10,000	4.120	1,000	52.78
2016			1,000	90.00

6

	Costless Collar (NYMEX)
	Oil
	Daily Volume (Bbls/d)	Floor Price ($)	Ceiling Price ($)
2016	1,000	45.00	54.75

During 2014, certain of our natural gas derivative instruments no longer qualified as cash flow hedges, as it was no longer probable, subsequent to the sale of our non-core Gulf of Mexico (“GOM”) conventional shelf properties (see Note 7 – Divestitures), that GOM natural gas production would be sufficient to cover the GOM volumes hedged. Accordingly, we discontinued hedge accounting for three natural gas contracts for the months of January through December 2015. 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 September 30, 2015, we had accumulated other comprehensive income of $41.1 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of September 30, 2015. We believe that approximately $37.7 million, net of tax, 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 September 30, 2015 and December 31, 2014:

Fair Value of Derivatives Qualifying as Hedging Instruments at
September 30, 2015
(In millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	61.4	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	5.7		Long-term liabilities: Fair value of derivative contracts	0.2
		$	67.1		$	0.2
Fair Value of Derivatives Qualifying as Hedging Instruments at
December 31, 2014
(In millions)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	127.0	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	14.3		Long-term liabilities: Fair value of derivative contracts	—
		$	141.3		$	—

The following tables disclose the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three and nine months ended September 30, 2015 and 2014:

7

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended September 30, 2015 and 2014
(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)
	2015		2014		Location	2015		2014			Location	2015		2014
Commodity contracts	$	31.6	$	47.1	Operating revenue - oil/natural gas production	$	39.9	$	(1.3	)	Derivative income (expense), net	$	1.2	$	2.1
Total	$	31.6	$	47.1		$	39.9	$	(1.3	)		$	1.2	$	2.1

(a) For the three months ended September 30, 2015, effective hedging contracts increased oil revenue by $36.3 million and increased natural gas revenue by $3.6 million. For the three months ended September 30, 2014, effective hedging contracts (decreased) oil revenue by $1.3 million and had a minimal effect on natural gas revenue.

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Nine Months Ended September 30, 2015 and 2014
(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)
	2015		2014		Location	2015		2014			Location	2015		2014
Commodity contracts	$	35.7	$	3.7	Operating revenue - oil/natural gas production	$	107.1	$	(17.6	)	Derivative income (expense), net	$	1.7	$	0.5
Total	$	35.7	$	3.7		$	107.1	$	(17.6	)		$	1.7	$	0.5

(a) For the nine months ended September 30, 2015, effective hedging contracts increased oil revenue by $96.8 million and increased natural gas revenue by $10.3 million. For the nine months ended September 30, 2014, effective hedging contracts (decreased) oil revenue by $10.0 million and (decreased) natural gas revenue by $7.6 million.

Derivatives not qualifying as hedging instruments:

The following table discloses the location and fair value amounts of our derivatives not qualifying as hedging instruments, as reported in our balance sheet, at September 30, 2015 and December 31, 2014:

Fair Value of Derivatives Not Qualifying as Hedging Instruments (In millions)
Description	Balance Sheet Location	September 30, 2015		December 31, 2014
Commodity contracts	Current assets: Fair value of derivative contracts	$	4.3	$	12.1

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 nine months ended September 30, 2015 and 2014.

8

Amount of Gain (Loss) Recognized in Derivative Income (Expense) (In millions)
	Three Months Ended September 30,					Nine Months Ended September 30,
Description	2015			2014		2015			2014
Commodity contracts:
Cash settlements	$	3.8		$	0.7	$	11.0		$	0.7
Change in fair value	(2.6		)	3.0		(7.9		)	1.5
Total gains (losses) on non-qualifying hedges	$	1.2		$	3.7	$	3.1		$	2.2

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. The following table presents the potential impact of the offset rights associated with our recognized assets and liabilities at September 30, 2015 (in millions):

	As Presented Without Netting			Effects of Netting			With Effects of Netting
Current assets: Fair value of derivative contracts	$	65.7		$	—		$	65.7
Long-term assets: Fair value of derivative contracts	5.7			(0.2		)	5.5
Current liabilities: Fair value of derivative contracts	—			—			—
Long-term liabilities: Fair value of derivative contracts	(0.2		)	0.2			—

As of December 31, 2014, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

Note 4 – Long-Term Debt

Long-term debt consisted of the following at:

	September 30, 2015		December 31, 2014
	(In millions)
1 3⁄4% Senior Convertible Notes due 2017	$	277.2	$	266.0
7 1⁄2% Senior Notes due 2022	775.0		775.0
Bank debt	—		—
Total long-term debt	$	1,052.2	$	1,041.0

Bank Debt. On June 24, 2014, we entered into an amended and restated 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. On September 30, 2015, our borrowing base under the bank credit facility was $500 million, we had no outstanding borrowings and $19.2 million of letters of credit had been issued pursuant to the bank credit facility, leaving $480.8 million of availability under the bank credit facility. On October 13, 2015, our borrowing base under the bank credit facility was reaffirmed at $500 million. As of November 3, 2015, we had no outstanding borrowings under the bank credit facility and $19.2 million of letters of credit had been issued pursuant to the bank credit facility, leaving $480.8 million of availability under the bank credit facility. 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 September 30, 2015, 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. If a reduction in our borrowing base were to fall below any outstanding balances under the bank credit facility plus any outstanding letters of credit, our agreement with the banks allows us one or more of three options to cure the borrowing base deficiency. We may (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil

9

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.

The bank credit facility is collateralized by substantially all of the assets of Stone and its material subsidiaries. They are required to mortgage, and grant a security interest in, their oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from their 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 the election of Stone. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. The bank credit facility provides for optional and mandatory prepayments and affirmative and negative covenants, including interest coverage ratio and leverage ratio maintenance covenants. We were in compliance with all covenants as of September 30, 2015.

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 corresponds to an initial conversion price of approximately $42.65 per share of our common stock. On September 30, 2015, our closing share price was $4.96 per share. 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.

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). 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.

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 7,033,470 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes, 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 7,033,470 shares of our common stock (the “Sold Warrants”) at a strike price of $55.91 per share of our common stock. 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 September 30, 2015, the carrying amount of the liability component of the 2017 Convertible Notes was $277.2 million. During the three and nine months ended September 30, 2015, we recognized $3.8 million and $11.1 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $1.1 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and nine months ended September 30, 2014, we recognized $3.5 million and $10.4 million, respectively, of interest expense for the amortization of the discount and $0.3 million and $1.0 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and nine months ended September 30, 2015, we recognized $1.3 million and $3.9 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes. During the three and nine months ended September 30, 2014, we recognized $1.3 million and $3.9 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

10

Note 5 – Asset Retirement Obligations

The change in our asset retirement obligations during the nine months ended September 30, 2015 is set forth below:

	Nine Months Ended September 30, 2015
	(In millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	316.4
Liabilities incurred	10.3
Liabilities settled	(59.8		)
Accretion expense	19.3
Asset retirement obligations as of the end of the period, including current portion	$	286.2

Note 6 – Income Taxes

For the three and nine months ended September 30, 2015, we recorded income tax benefits of $15.8 million and $280.8 million, respectively. The income tax benefits were a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (see Note 10 - Investment in Oil and Gas Properties). Our effective tax rate for the three and nine months ended September 30, 2015 was 5.1% and 26.7%, respectively. These percentages differed from the federal statutory rate of 35.0% primarily due to the establishment of a valuation allowance against deferred tax assets, state income taxes and other permanent differences.

As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred over the past four quarters, we determined 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 $96.5 million valuation allowance against a portion of our deferred tax assets in the third quarter of 2015. 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.

Note 7 – Divestitures

On July 31, 2014, we completed the sale of certain of our non-core properties in the GOM conventional shelf for cash consideration of approximately $177.6 million, after giving effect to preliminary purchase price adjustments. All of the proceeds from this sale were deposited with a Qualified Intermediary (under the terms of a Qualified Trust Agreement and Exchange Agreement) for potential reinvestment in like-kind replacement property as defined under Section 1031 of the Internal Revenue Code and were included in our balance sheet as restricted cash at December 31, 2014. Compliance with provisions under the Qualified Trust Agreement and Exchange Agreement provided for deferral of taxable gain on these sales proceeds. We identified qualified replacement properties and had until January 27, 2015 to close on an acquisition of such properties in order to achieve deferral of our taxable gain. We did not close on such a transaction by January 27, 2015, and the funds were released from restrictions and reclassified to cash and cash equivalents at such date.

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 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 September 30, 2015 and December 31, 2014, we held certain financial assets and liabilities 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 and collar contracts are included within the Level 2 fair value hierarchy. For a more detailed description of our derivative instruments, see Note 3 – 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.

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The following tables present our assets and liabilities that are measured at fair value on a recurring basis at September 30, 2015:

	Fair Value Measurements at
	September 30, 2015
Assets	Total		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)	$	8.3	$	8.3	$	—	$	—
Derivative contracts	71.4		—		71.4		—
Total	$	79.7	$	8.3	$	71.4	$	—

	Fair Value Measurements at
	September 30, 2015
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In millions)
Derivative contracts	$	0.2	$	—	$	0.2	$	—
Total	$	0.2	$	—	$	0.2	$	—

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014:

	Fair Value Measurements at
	December 31, 2014
Assets	Total		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)	$	8.4	$	8.4	$	—	$	—
Derivative contracts	153.5		—		153.5		—
Total	$	161.9	$	8.4	$	153.5	$	—

	Fair Value Measurements at
	December 31, 2014
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In millions)
Derivative contracts	$	—	$	—	$	—	$	—
Total	$	—	$	—	$	—	$	—

The fair value of cash and cash equivalents approximated book value at September 30, 2015 and December 31, 2014. As of September 30, 2015 and December 31, 2014, the fair value of the liability component of the 2017 Convertible Notes was approximately $244.0 million and $252.6 million, respectively. As of September 30, 2015 and December 31, 2014, the fair value of the 7 1⁄2% Senior Notes due 2022 (the “2022 Notes”) was approximately $484.4 million and $664.6 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 4 – Long-Term Debt) at inception, September 30, 2015 and December 31, 2014. The fair value of the liability was estimated using an income approach. The

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significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

Note 9 – Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss) by component for the three and nine months ended September 30, 2015 were as follows (in millions):

	Cash Flow Hedges			Foreign Currency Items			Total
Three Months Ended September 30, 2015
Beginning balance, net of tax	$	46.5		$	(5.8	)	$	40.7
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	31.6			—			31.6
Foreign currency translations	—			(0.2		)	(0.2		)
Income tax effect	(11.5		)	—			(11.5		)
Net of tax	20.1			(0.2		)	19.9
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	39.9			—			39.9
Income tax effect	(14.4		)	—			(14.4		)
Net of tax	25.5			—			25.5
Other comprehensive income (loss), net of tax	(5.4		)	(0.2		)	(5.6		)
Ending balance, net of tax	$	41.1		$	(6.0	)	$	35.1

	Cash Flow Hedges			Foreign Currency Items			Total
Nine Months Ended September 30, 2015
Beginning balance, net of tax	$	86.8		$	(3.5	)	$	83.3
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	35.7			—			35.7
Foreign currency translations	—			(2.5		)	(2.5		)
Income tax effect	(12.8		)	—			(12.8		)
Net of tax	22.9			(2.5		)	20.4
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	107.1			—			107.1
Income tax effect	(38.5		)	—			(38.5		)
Net of tax	68.6			—			68.6
Other comprehensive income (loss), net of tax	(45.7		)	(2.5		)	(48.2		)
Ending balance, net of tax	$	41.1		$	(6.0	)	$	35.1

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Changes in accumulated other comprehensive income (loss) by component for the three and nine months ended September 30, 2014, were as follows (in millions):

	Cash Flow Hedges			Foreign Currency Items			Total
Three Months Ended September 30, 2014
Beginning balance, net of tax	$	(17.8	)	$	(0.4	)	$	(18.2	)
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	47.1			—			47.1
Foreign currency translations	—			(1.6		)	(1.6		)
Income tax effect	(16.9		)	—			(16.9		)
Net of tax	30.2			(1.6		)	28.6
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	(1.3		)	—			(1.3		)
Income tax effect	0.5			—			0.5
Net of tax	(0.8		)	—			(0.8		)
Other comprehensive income (loss), net of tax	31.0			(1.6		)	29.4
Ending balance, net of tax	$	13.2		$	(2.0	)	$	11.2

	Cash Flow Hedges			Foreign Currency Items			Total
Nine Months Ended September 30, 2014
Beginning balance, net of tax	$	(1.4	)	$	(0.7	)	$	(2.1	)
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	3.7			—			3.7
Foreign currency translations	—			(1.3		)	(1.3		)
Income tax effect	(1.2		)	—			(1.2		)
Net of tax	2.5			(1.3		)	1.2
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	(17.6		)	—			(17.6		)
Derivative expense, net	(1.5		)	—			(1.5		)
Income tax effect	7.0			—			7.0
Net of tax	(12.1		)	—			(12.1		)
Other comprehensive income (loss), net of tax	14.6			(1.3		)	13.3
Ending balance, net of tax	$	13.2		$	(2.0	)	$	11.2

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 September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $295.7 million based on twelve-month average prices, net of applicable differentials, of $57.76 per barrel of oil, $2.44 per Mcf of natural gas and $23.04 per barrel of natural gas liquids ("NGLs"). The write-down at September 30, 2015 was decreased by $42.7 million as a result of hedges. At June 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $179.1 million based on twelve-month average prices, net of applicable differentials, of $68.68 per barrel of oil, $2.47 per Mcf of natural gas and $29.13 per barrel of NGLs. The write-down at June 30, 2015 was decreased by $47.8 million as a result of hedges. At March 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $491.4 million based on twelve-month average prices, net of applicable differentials, of $78.99 per barrel of oil, $2.96 per Mcf of natural gas and $28.82 per barrel of NGLs. The write-down at March 31, 2015 was decreased by $28.7 million as a result of hedges.

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In April 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Upon a more complete evaluation of this project and in response to the significant decline in commodity prices over the last several months, we have suspended our business development effort in Canada. Accordingly, at June 30, 2015, we recognized a write-down of our Canadian oil and gas properties of $45.2 million.

Note 11 – Commitments and Contingencies

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 August 2, 2013, Kimmeridge Energy Exploration Fund, L.P. (“Kimmeridge”) filed a lawsuit against Stone in the 15th Judicial District Court in Lafayette Parish, Louisiana seeking damages in the amount of $18,372,819 plus interest, costs and attorney fees. Kimmeridge alleged that Stone was obligated to pay Kimmeridge (1) $1,118,878 for brokerage costs incurred pursuant to a letter of understanding and (2) $17,253,941 pursuant to a letter of intent which, according to Kimmeridge’s pleadings, required Stone to negotiate in good faith and close an acquisition of mineral interests in the Illinois basin. The court granted summary judgment in favor of Stone, limiting damages on Kimmeridge’s $17,253,941 claim to $1,000,000 and reducing Stone’s exposure at trial for both claims to $2,118,878. During the three months ended June 30, 2015, Stone and Kimmeridge settled both claims for an amount within the previously disclosed range of loss (between $0 and $2,118,878).

Note 12 – 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 September 30, 2015 and December 31, 2014 and for the three and nine month periods ended September 30, 2015 and 2014 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

SEPTEMBER 30, 2015

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	63,322		$	10,042		$	1,110		$	—		$	74,474
Accounts receivable	25,445			88,193			13			(55,792		)	57,859
Fair value of derivative contracts	—			65,700			—			—			65,700
Inventory	3,426			283			—			—			3,709
Other current assets	9,162			—			41			—			9,203
Total current assets	101,355			164,218			1,164			(55,792		)	210,945
Oil and gas properties, full cost method:
Proved	1,821,870			7,341,224			41,599			—			9,204,693
Less: accumulated DD&A	(2,046,465		)	(6,111,909		)	(41,599		)	—			(8,199,973		)
Net proved oil and gas properties	(224,595		)	1,229,315			—			—			1,004,720
Unevaluated	301,501			215,085			2,377			—			518,963
Other property and equipment, net	30,327			—			—			—			30,327
Fair value of derivative contracts	—			5,734			—			—			5,734
Other assets, net	24,217			1,191			215			—			25,623
Investment in subsidiary	1,280,184			—			3,590			(1,283,774		)	—
Total assets	$	1,512,989		$	1,615,543		$	7,346		$	(1,339,566	)	$	1,796,312
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	66,623		$	45,487		$	9,736		$	(55,792	)	$	66,054
Undistributed oil and gas proceeds	9,644			817			—			—			10,461
Accrued interest	22,241			—			—			—			22,241
Asset retirement obligations	—			42,624			—			—			42,624
Other current liabilities	41,575			559			—			—			42,134
Total current liabilities	140,083			89,487			9,736			(55,792		)	183,514
Long-term debt	1,052,183			—			—			—			1,052,183
Asset retirement obligations	3,847			239,720			—			—			243,567
Fair value of derivative contracts	—			172			—			—			172
Other long-term liabilities	25,347			—			—			—			25,347
Total liabilities	1,221,460			329,379			9,736			(55,792		)	1,504,783
Commitments and contingencies
Stockholders’ equity:
Common stock	553			—			—			—			553
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,643,746			1,367,434			100,047			(1,467,481		)	1,643,746
Accumulated deficit	(1,386,967		)	(122,362		)	(90,368		)	212,730			(1,386,967		)
Accumulated other comprehensive income (loss)	35,057			41,092			(12,069		)	(29,023		)	35,057
Total stockholders’ equity	291,529			1,286,164			(2,390		)	(1,283,774		)	291,529
Total liabilities and stockholders’ equity	$	1,512,989		$	1,615,543		$	7,346		$	(1,339,566	)	$	1,796,312

16

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2014

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	72,886		$	1,450		$	152		$	—		$	74,488
Restricted cash	177,647			—			—			—			177,647
Accounts receivable	73,711			46,615			33			—			120,359
Fair value of derivative contracts	—			139,179			—			—			139,179
Current income tax receivable	7,212			—			—			—			7,212
Deferred taxes *	4,095			—			—			(4,095		)	—
Inventory	1,011			2,698			—			—			3,709
Other current assets	8,112			—			6			—			8,118
Total current assets	344,674			189,942			191			(4,095		)	530,712
Oil and gas properties, full cost method:
Proved	1,689,802			7,127,466			—			—			8,817,268
Less: accumulated DD&A	(970,387		)	(6,000,244		)	—			—			(6,970,631		)
Net proved oil and gas properties	719,415			1,127,222			—			—			1,846,637
Unevaluated	289,556			241,230			36,579			—			567,365
Other property and equipment, net	32,340			—			—			—			32,340
Fair value of derivative contracts	—			14,333			—			—			14,333
Other assets, net	20,857			1,360			5,007			—			27,224
Investment in subsidiary	1,050,546			—			41,638			(1,092,184		)	—
Total assets	$	2,457,388		$	1,574,087		$	83,415		$	(1,096,279	)	$	3,018,611
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	74,756		$	57,873		$	—		$	—		$	132,629
Undistributed oil and gas proceeds	22,158			1,074			—			—			23,232
Accrued interest	9,022			—			—			—			9,022
Deferred taxes *	—			24,214			—			(4,095		)	20,119
Asset retirement obligations	—			69,400			—			—			69,400
Other current liabilities	49,306			199			—			—			49,505
Total current liabilities	155,242			152,760			—			(4,095		)	303,907
Long-term debt	1,041,035			—			—			—			1,041,035
Deferred taxes *	117,206			169,137			—			—			286,343
Asset retirement obligations	3,588			243,421			—			—			247,009
Other long-term liabilities	38,714			—			—			—			38,714
Total liabilities	1,355,785			565,318			—			(4,095		)	1,917,008
Commitments and contingencies
Stockholders’ equity:
Common stock	549			—			—			—			549
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,633,307			1,362,684			90,339			(1,453,023		)	1,633,307
Accumulated earnings (deficit)	(614,708		)	(440,699		)	12			440,687			(614,708		)
Accumulated other comprehensive income (loss)	83,315			86,784			(6,936		)	(79,848		)	83,315
Total stockholders’ equity	1,101,603			1,008,769			83,415			(1,092,184		)	1,101,603
Total liabilities and stockholders’ equity	$	2,457,388		$	1,574,087		$	83,415		$	(1,096,279	)	$	3,018,611

* Deferred income taxes have been allocated to our Guarantor Subsidiaries where related oil and gas properties reside.

17

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2015

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	1,633		$	103,380		$	—		$	—		$	105,013
Natural gas production	7,111			10,256			—			—			17,367
Natural gas liquids production	3,502			2,478			—			—			5,980
Other operational income	1,392			—			—			—			1,392
Derivative income, net	—			2,444			—			—			2,444
Total operating revenue	13,638			118,558			—			—			132,196
Operating expenses:
Lease operating expenses	2,680			21,562			2			—			24,244
Transportation, processing and gathering expenses	13,697			4,511			—			—			18,208
Production taxes	1,777			275			—			—			2,052
Depreciation, depletion and amortization	27,518			34,418			—			—			61,936
Write-down of oil and gas properties	295,679			—			—			—			295,679
Accretion expense	92			6,406			—			—			6,498
Salaries, general and administrative expenses	19,348			200			4			—			19,552
Incentive compensation expense	794			—			—			—			794
Other operational expenses	142			300			—			—			442
Total operating expenses	361,727			67,672			6			—			429,405
Income (loss) from operations	(348,089		)	50,886			(6		)	—			(297,209		)
Other (income) expenses:
Interest expense	10,871			1			—			—			10,872
Interest income	(39		)	(7		)	(1		)	—			(47		)
Other income	(117		)	(294		)	—			—			(411		)
Other expense	148			—			—			—			148
(Income) loss from investment in subsidiaries	(227,973		)	—			16,272			211,701			—
Total other (income) expenses	(217,110		)	(300		)	16,271			211,701			10,562
Income (loss) before taxes	(130,979		)	51,186			(16,277		)	(211,701		)	(307,771		)
Provision (benefit) for income taxes:
Deferred	160,986			(193,059		)	16,267			—			(15,806		)
Total income taxes	160,986			(193,059		)	16,267			—			(15,806		)
Net income (loss)	$	(291,965	)	$	244,245		$	(32,544	)	$	(211,701	)	$	(291,965	)
Comprehensive income (loss)	$	(297,564	)	$	244,245		$	(32,544	)	$	(211,701	)	$	(297,564	)

18

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2014

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	11,692		$	112,103		$	—		$	—		$	123,795
Natural gas production	16,001			14,153			—			—			30,154
Natural gas liquids production	15,820			5,194			—			—			21,014
Other operational income	2,417			51			—			—			2,468
Derivative income, net	—			5,782			—			—			5,782
Total operating revenue	45,930			137,283			—			—			183,213
Operating expenses:
Lease operating expenses	5,619			37,942			—			—			43,561
Transportation, processing and gathering expenses	14,379			2,342			—			—			16,721
Production taxes	2,936			715			—			—			3,651
Depreciation, depletion and amortization	36,598			43,693			—			—			80,291
Write-down of oil and gas properties	47,130			—			—			—			47,130
Accretion expense	56			6,483			—			—			6,539
Salaries, general and administrative expenses	16,273			1			12			—			16,286
Incentive compensation expense	3,092			—			—			—			3,092
Other operational expenses	294			4			—			—			298
Total operating expenses	126,377			91,180			12			—			217,569
Income (loss) from operations	(80,447		)	46,103			(12		)	—			(34,356		)
Other (income) expenses:
Interest expense	10,316			7			—			—			10,323
Interest income	(76		)	(82		)	(11		)	—			(169		)
Other income	(164		)	(531		)	—			—			(695		)
Other expense	95			—			—			—			95
(Income) loss from investment in subsidiaries	(29,894		)	—			2			29,892			—
Total other (income) expenses	(19,723		)	(606		)	(9		)	29,892			9,554
Income (loss) before taxes	(60,724		)	46,709			(3		)	(29,892		)	(43,910		)
Provision (benefit) for income taxes:
Deferred	(31,309		)	16,814			—			—			(14,495		)
Total income taxes	(31,309		)	16,814			—			—			(14,495		)
Net income (loss)	$	(29,415	)	$	29,895		$	(3	)	$	(29,892	)	$	(29,415	)
Comprehensive income (loss)	$	(65	)	$	29,895		$	(3	)	$	(29,892	)	$	(65	)

19

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2015

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	12,487		$	311,618		$	—		$	—		$	324,105
Natural gas production	39,375			33,236			—			—			72,611
Natural gas liquids production	21,458			7,921			—			—			29,379
Other operational income	3,184			—			—			—			3,184
Derivative income, net	—			4,871			—			—			4,871
Total operating revenue	76,504			357,646			—			—			434,150
Operating expenses:
Lease operating expenses	12,767			66,481			2			—			79,250
Transportation, processing and gathering expenses	47,779			8,072			—			—			55,851
Production taxes	5,411			983			—			—			6,394
Depreciation, depletion and amortization	113,682			112,627			—			—			226,309
Write-down of oil and gas properties	966,216			—			45,169			—			1,011,385
Accretion expense	274			19,041			—			—			19,315
Salaries, general and administrative expenses	52,747			201			29			—			52,977
Incentive compensation expense	3,621			—			—			—			3,621
Other operational expenses	1,312			300			—			—			1,612
Total operating expenses	1,203,809			207,705			45,200			—			1,456,714
Income (loss) from operations	(1,127,305		)	149,941			(45,200		)	—			(1,022,564		)
Other (income) expenses:
Interest expense	31,687			22			—			—			31,709
Interest income	(186		)	(42		)	(7		)	—			(235		)
Other income	(437		)	(727		)	(3		)	—			(1,167		)
Other expense	148			—			—			—			148
(Income) loss from investment in subsidiaries	(273,147		)	—			45,190			227,957			—
Total other (income) expenses	(241,935		)	(747		)	45,180			227,957			30,455
Income (loss) before taxes	(885,370		)	150,688			(90,380		)	(227,957		)	(1,053,019		)
Provision (benefit) for income taxes:
Deferred	(113,111		)	(167,649		)	—			—			(280,760		)
Total income taxes	(113,111		)	(167,649		)	—			—			(280,760		)
Net income (loss)	$	(772,259	)	$	318,337		$	(90,380	)	$	(227,957	)	$	(772,259	)
Comprehensive income (loss)	$	(820,517	)	$	318,337		$	(90,380	)	$	(227,957	)	$	(820,517	)

20

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2014

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	24,182		$	380,295		$	—		$	—		$	404,477
Natural gas production	65,640			67,543			—			—			133,183
Natural gas liquids production	44,293			20,627			—			—			64,920
Other operational income	5,121			394			—			—			5,515
Derivative income, net	—			2,667			—			—			2,667
Total operating revenue	139,236			471,526			—			—			610,762
Operating expenses:
Lease operating expenses	14,678			125,240			—			—			139,918
Transportation, processing and gathering expenses	35,152			10,293			—			—			45,445
Production taxes	6,520			3,450			—			—			9,970
Depreciation, depletion and amortization	95,038			160,734			—			—			255,772
Write-down of oil and gas properties	47,130			—			—			—			47,130
Accretion expense	185			21,642			—			—			21,827
Salaries, general and administrative expenses	49,237			3			12			—			49,252
Incentive compensation expense	10,129			—			—			—			10,129
Other operational expenses	470			40			—			—			510
Total operating expenses	258,539			321,402			12			—			579,953
Income (loss) from operations	(119,303		)	150,124			(12		)	—			30,809
Other (income) expenses:
Interest expense	28,549			44			—			—			28,593
Interest income	(301		)	(181		)	(23		)	—			(505		)
Other income	(537		)	(1,587		)	—			—			(2,124		)
Other expense	274			—			—			—			274
Income from investment in subsidiaries	(97,186		)	—			(10		)	97,196			—
Total other (income) expenses	(69,201		)	(1,724		)	(33		)	97,196			26,238
Income (loss) before taxes	(50,102		)	151,848			21			(97,196		)	4,571
Provision (benefit) for income taxes:
Deferred	(51,074		)	54,673			—			—			3,599
Total income taxes	(51,074		)	54,673			—			—			3,599
Net income	$	972		$	97,175		$	21		$	(97,196	)	$	972
Comprehensive income	$	14,223		$	97,175		$	21		$	(97,196	)	$	14,223

21

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2015

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(772,259	)	$	318,337		$	(90,380	)	$	(227,957	)	$	(772,259	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	113,682			112,627			—			—			226,309
Write-down of oil and gas properties	966,216			—			45,169			—			1,011,385
Accretion expense	274			19,041			—			—			19,315
Deferred income tax benefit	(113,111		)	(167,649		)	—			—			(280,760		)
Settlement of asset retirement obligations	(15		)	(59,811		)	—			—			(59,826		)
Non-cash stock compensation expense	9,163			—			—			—			9,163
Non-cash derivative expense	—			10,854			—			—			10,854
Non-cash interest expense	13,210			—			—			—			13,210
Change in current income taxes	7,211			—			—			—			7,211
Non-cash (income) expense from investment in subsidiaries	(273,147		)	—			45,190			227,957			—
Change in intercompany receivables/payables	31,320			(41,056		)	9,736			—			—
Decrease in accounts receivable	29,561			4,317			17			—			33,895
Increase in other current assets	(1,050		)	—			(40		)	—			(1,090		)
(Increase) decrease in inventory	(2,415		)	2,415			—			—			—
Decrease in accounts payable	(7,562		)	(4,030		)	—			—			(11,592		)
Increase (decrease) in other current liabilities	(6,855		)	102			—			—			(6,753		)
Other	645			(727		)							(82		)
Net cash (used in) provided by operating activities	(5,132		)	194,420			9,692			—			198,980
Cash flows from investing activities:
Investment in oil and gas properties	(177,497		)	(197,471		)	(10,560		)	—			(385,528		)
Proceeds from sale of oil and gas properties, net of expenses	—			11,643			—			—			11,643
Investment in fixed and other assets	(1,455		)	—			—			—			(1,455		)
Change in restricted funds	177,647			—			1,828			—			179,475
Investment in subsidiaries	—			—			(9,708		)	9,708			—
Net cash used in investing activities	(1,305		)	(185,828		)	(18,440		)	9,708			(195,865		)
Cash flows from financing activities:
Proceeds from bank borrowings	5,000			—			—			—			5,000
Repayments of bank borrowings	(5,000		)	—			—			—			(5,000		)
Equity proceeds from parent	—			—			9,708			(9,708		)	—
Net payments for share-based compensation	(3,127		)	—			—			—			(3,127		)
Net cash (used in) provided by financing activities	(3,127		)	—			9,708			(9,708		)	(3,127		)
Effect of exchange rate changes on cash	—			—			(2		)	—			(2		)
Net change in cash and cash equivalents	(9,564		)	8,592			958			—			(14		)
Cash and cash equivalents, beginning of period	72,886			1,450			152			—			74,488
Cash and cash equivalents, end of period	$	63,322		$	10,042		$	1,110		$	—		$	74,474

22

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2014

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income	$	972		$	97,175		$	21		$	(97,196	)	$	972
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	95,038			160,734			—			—			255,772
Write-down of oil and gas properties	47,130			—			—			—			47,130
Accretion expense	185			21,642			—			—			21,827
Deferred income tax (benefit) provision	(51,074		)	54,673			—			—			3,599
Settlement of asset retirement obligations	(84		)	(47,133		)	—			—			(47,217		)
Non-cash stock compensation expense	8,409			—			—			—			8,409
Non-cash derivative income	—			(2,386		)	—			—			(2,386		)
Non-cash interest expense	12,393			—			—			—			12,393
Change in current income taxes	(6		)	—			—			—			(6		)
Non-cash income from investment in subsidiaries	(97,185		)	—			(11		)	97,196			—
Change in intercompany receivables/payables	(119,004		)	90,313			28,691			—			—
(Increase) decrease in accounts receivable	125,593			(127,363		)	(35		)	—			(1,805		)
Increase in other current assets	(2		)	—			(8		)	—			(10		)
Increase (decrease) in accounts payable	900			(4,447		)	—			—			(3,547		)
Increase (decrease) in other current liabilities	39,329			(1,888		)	—			—			37,441
Other	1,414			(1,586		)	—			—			(172		)
Net cash provided by operating activities	64,008			239,734			28,658			—			332,400
Cash flows from investing activities:
Investment in oil and gas properties	(225,831		)	(480,686		)	(20,971		)	—			(727,488		)
Proceeds from sale of oil and gas properties, net of expenses	12,197			211,102			—			—			223,299
Investment in fixed and other assets	(8,790		)	—			—			—			(8,790		)
Change in restricted funds	(177,647		)	—			(8,105		)	—			(185,752		)
Investment in subsidiaries	—			—			(29,253		)	29,253			—
Net cash used in investing activities	(400,071		)	(269,584		)	(58,329		)	29,253			(698,731		)
Cash flows from financing activities:
Net proceeds from issuance of common stock	225,999			—			—			—			225,999
Deferred financing costs	(3,329		)	—			—			—			(3,329		)
Equity proceeds from parent	—			—			29,253			(29,253		)	—
Net payments for share-based compensation	(7,161		)	—			—			—			(7,161		)
Net cash provided by financing activities	215,509			—			29,253			(29,253		)	215,509
Effect of exchange rate on cash	—			—			(95		)	—			(95		)
Net change in cash and cash equivalents	(120,554		)	(29,850		)	(513		)	—			(150,917		)
Cash and cash equivalents, beginning of period	246,294			84,290			640			—			331,224
Cash and cash equivalents, end of period	$	125,740		$	54,440		$	127		$	—		$	180,307

23

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 2014 Annual Report on Form 10-K and in this Form 10-Q.

Forward-looking statements 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 risked 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 amount, nature and timing of any potential acquisition or divestiture transactions;

• 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;

• the availability of capital on economic terms to fund our capital expenditures, acquisitions and other obligations;

• our level of indebtedness, liquidity and compliance with debt covenants;

• 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 replace 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;

• drilling and other operating risks;

• unsuccessful exploration and development drilling activities;

• hurricanes and other weather conditions;

• adverse effects of changes in applicable tax, environmental, derivatives and other regulatory 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.

24

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 2014 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2014 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 2014 Annual Report on Form 10-K.

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 the 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 Shale in Appalachia.

Critical Accounting Estimates

Our 2014 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 2014 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 2014 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.

Known Trends and Uncertainties

Declining Commodity Prices – We experienced a significant decline in oil, natural gas and natural gas liquid prices during the second half of 2014, with lower prices continuing throughout 2015, which has resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015. Additionally, the decline in commodity prices has 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 at December 31, 2014 and March 31, June 30, and September 30, 2015.  Through the first nine months of 2015, we estimate that lower commodity prices have resulted in downward revisions of our estimated proved reserve quantities of approximately 48 MMBoe or 290 Bcfe, most of which were proved undeveloped reserves from our Appalachia properties. If NYMEX commodity prices remain at current levels (approximately $45.00 per Bbl of oil and $2.30 per MMBtu of natural gas) for the remainder of 2015, we would reasonably expect to incur further downward revisions of our estimated proved reserve quantities between 25 and 28 MMBoe (150 - 168 Bcfe) and would expect to recognize an additional ceiling test write-down between $250 and $350 million (pre-tax) in the fourth quarter of 2015. Continued low commodity prices or further declines in commodity prices, including widening negative price differentials (particularly in Appalachia), would likely have a further material adverse impact on the

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estimated value and quantities of our proved reserves, our financial position, results of operations and future cash flows and could substantially reduce the available borrowings under our bank credit facility and constrain our capital budgets beyond 2015.

Realizability of Deferred Tax Assets– As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred over the past four quarters, we determined 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 $96.5 million valuation allowance against a portion of our deferred tax assets in the third quarter of 2015. 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. As a result of the additional ceiling test write-down expected in the fourth quarter of 2015, we expect the valuation allowance to increase in the fourth quarter of 2015.

BOEM Bonding Requirements – The Bureau of Ocean Energy Management (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, on September 22, 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 a Notice to Lessees (“NTL”) that will supersede the agency’s current NTL regarding financial assurance options that became effective in August 2008.  Among other things, the Draft Guidance proposes to substantially curtail the “waiver” exemption currently allowed by BOEM, whereby we and many other operators on the Outer Continental Shelf have been able to seek an exemption from posting bonds or other forms of financial assurance for our plugging, abandonment and decommissioning obligations by self-insuring for those liabilities, provided that those obligations did not exceed 50% of our net worth.  Under the Draft Guidance, this waiver option would be limited to no more than 10% of the tangible net worth of the operator.  The BOEM proposes to establish a phased-in period for establishing compliance with its new bonding requirements, whereby operators may seek to provide financial assurance for their plugging, abandonment and decommissioning obligations pursuant to a “tailored plan” that is approved by the BOEM.  Once an operator’s new financial assurance plan is approved by BOEM, if additional financial assurance is required because the plugging, abandonment and decommissioning costs are estimated to exceed 10% of an operator’s net worth, then the affected operator will be required to post the additional assurance in three approximately equal installments of one-third each, by no later than approximately 120, 240 and 360 calendar days, respectively, from the date of BOEM approval of the tailored plan.  We currently expect the Draft Guidance to be finalized and a new NTL to be issued by early 2016, which means that we could lose a portion of our exemption beginning in late 2016, depending on the estimated cost of our plugging, abandonment and decommissioning obligations and our estimated net worth at that time.

Although we believe we are currently in compliance with BOEM’s financial assurance requirements, the agency may reassess our plugging, abandonment and decommissioning obligations, re-evaluate the adequacy of our financial assurances and require us to provide additional forms of financial assurance for most or all of our properties in the GOM. It is possible that future agency action or our inability to meet the required levels of net worth for self-insurance as a result of declining commodity prices could result in a loss of our financial assurance exemption and could require us to post bonds or letters of credit at a potentially significant cost.

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.

Deep Water Operations – We are currently operating two significant properties in the deep water of the GOM. Additionally, we are engaged in deep water drilling operations. Operations in the deep water can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, 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.

Appalachia Production Shut-ins – On September 1, 2015, we shut in our Mary field in Appalachia, curtailing approximately 100-110 Mmcfe of production per day, leaving approximately 25 Mmcfe per day producing from the Heather and Buddy fields in Appalachia. Low commodity pricing, including negative price differentials in the area, combined with transportation, processing and gathering fees, reduced the operating margins to an unacceptable level. If operating margins do not return to acceptable levels, production may remain shut-in, affecting our future operating results as well as future development plans.

Liquidity and Capital Resources

As of November 3, 2015, we had cash on hand of approximately $68 million and $480.8 million of availability under our bank credit facility. On October 13, 2015, our borrowing base under the bank credit facility was reaffirmed at $500 million following the lenders' semi-annual redetermination process. Our capital expenditure budget for 2015 has been set at $450 million, which assumes planned sales of minority working interests in certain targeted assets. The budget excludes material divestitures and acquisitions and

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capitalized salaries, general and administrative (“SG&A”) expenses and interest. While certain of the planned sales have been completed, others are still being actively marketed but may not be executed, which may put upward pressure on our 2015 capital expenditures. However, we do not anticipate that we will materially exceed the $450 million budget. We currently project that our 2015 capital expenditures may exceed the $450 million budget by approximately $25 million. Based on our current outlook of commodity prices and our estimated production, we expect our 2015 capital expenditures to exceed our cash flows from operating activities. We intend to fund our 2015 capital expenditures with cash flows from operating activities, cash on hand and borrowings under our bank credit facility.

Although a capital expenditure budget for 2016 has not yet been approved by the board of directors, we anticipate that our budget will be closely aligned with our expected 2016 cash flows from operating activities. Based on our current outlook of commodity prices and our estimated production for 2016, we expect to fund our 2016 capital expenditures with cash flows from operating activities and borrowings under our bank credit facility. 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, 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 outside of our control.

Cash Flows and Working Capital. Net cash provided by operating activities totaled $199.0 million during the nine months ended September 30, 2015 compared to $332.4 million during the comparable period in 2014. The decrease was primarily due to the decline in oil, natural gas and NGL prices and an increase in transportation, processing and gathering expenses, partially offset by a decline in lease operating expenses. See "Results of Operations" for additional information relative to commodity prices, production and operating expense variances.

Net cash used in investing activities totaled $195.9 million during the nine months ended September 30, 2015, which primarily represents our investment in oil and gas properties of $385.5 million, offset by $179.5 million of previously restricted proceeds from the sale of oil and gas properties and $11.6 million of proceeds from the sale of oil and gas properties. Net cash used in investing activities totaled $698.7 million during the nine months ended September 30, 2014, which primarily represents our investment in oil and gas properties of $727.5 million, offset by proceeds from the sale of oil and gas properties of $37.5 million.

Net cash used in financing activities totaled $3.1 million during the nine months ended September 30, 2015, which primarily represents net payments for share-based compensation. During the nine months ended September 30, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility. Net cash provided by financing activities totaled $215.5 million during the nine months ended September 30, 2014, which primarily represents net proceeds from the sale of common stock of approximately $226.0 million, offset by net payments for share-based compensation of approximately $7.2 million and deferred financing costs of approximately $3.3 million associated with our bank credit facility.

We had working capital at September 30, 2015 of $27.4 million.

Capital Expenditures. During the three months ended September 30, 2015, additions to oil and gas property costs of $119.6 million included $6.0 million of capitalized SG&A expenses (inclusive of incentive compensation) and $10.3 million of capitalized interest. During the nine months ended September 30, 2015, additions to oil and gas property costs of $339.0 million included $1.2 million of lease and property acquisition costs, $21.9 million of capitalized SG&A expenses (inclusive of incentive compensation) and $31.9 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities.

Bank Credit Facility. On June 24, 2014, we entered into an amended and restated 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. On October 13, 2015, our borrowing base under the bank credit facility was reaffirmed at $500 million. Continued low commodity prices, further declines in commodity prices and/or widening negative price differentials (particularly in Appalachia) will likely have a material adverse impact on the value of our estimated proved reserves and could result in reductions of our borrowing base. As of November 3, 2015, we had no outstanding borrowings under the bank credit facility and $19.2 million of letters of credit had been issued pursuant to the bank credit facility, leaving $480.8 million of availability under the bank credit facility. The bank credit facility 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 base redetermined. The bank credit facility is collateralized by substantially all of the assets of Stone and its material subsidiaries. They are required to mortgage and grant a security interest in their oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from their proved oil and natural gas reserves reviewed in determining the borrowing base.

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Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at the election of Stone. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. Under the financial covenants of our bank credit facility, 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 2.50 to 1. As of September 30, 2015, our Consolidated Funded Debt to consolidated EBITDA ratio was 2.99 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 8.45 to 1. In addition, our bank credit facility 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 September 30, 2015.

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 2014 Annual Report on Form 10-K. There have been no material changes to this disclosure during the nine months ended September 30, 2015.

Results of Operations

The following tables set forth certain information with respect to our oil and gas operations:

	Three Months Ended September 30,
	2015		2014		Variance			% Change
Production:
Oil (MBbls)	1,509		1,329		180			14	%
Natural gas (MMcf)	8,328		10,891		(2,563		)	(24	)%
NGLs (MBbls)	765		495		270			55	%
Oil, natural gas and NGLs (MMcfe)	21,972		21,835		137			1	%
Revenue data (in thousands): (1)
Oil revenue	$	105,013	$	123,795	$	(18,782	)	(15	)%
Natural gas revenue	17,367		30,154		(12,787		)	(42	)%
NGLs revenue	5,980		21,014		(15,034		)	(72	)%
Total oil, natural gas and NGL revenue	$	128,360	$	174,963	$	(46,603	)	(27	)%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	45.51	$	94.17	$	(48.66	)	(52	)%
Natural gas (per Mcf)	1.65		2.77		(1.12		)	(40	)%
NGLs (per Bbl)	7.82		42.45		(34.63		)	(82	)%
Oil, natural gas and NGLs (per Mcfe)	4.02		8.07		(4.05		)	(50	)%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	69.59	$	93.15	$	(23.56	)	(25	)%
Natural gas (per Mcf)	2.09		2.77		(0.68		)	(25	)%
NGLs (per Bbl)	7.82		42.45		(34.63		)	(82	)%
Oil, natural gas and NGLs (per Mcfe)	5.84		8.01		(2.17		)	(27	)%
Expenses (per Mcfe):
Lease operating expenses	$	1.10	$	2.00	$	(0.90	)	(45	)%
Transportation, processing and gathering expenses	0.83		0.77		0.06			8	%
SG&A expenses (2)	0.89		0.75		0.14			19	%
DD&A expense on oil and gas properties	2.77		3.63		(0.86		)	(24	)%

(1) Includes the cash settlement of effective hedging contracts

(2) Excludes incentive compensation expense

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	Nine Months Ended September 30,
	2015		2014		Variance			% Change
Production:
Oil (MBbls)	4,665		4,228		437			10	%
Natural gas (MMcf)	32,066		35,895		(3,829		)	(11	)%
NGLs (MBbls)	2,242		1,472		770			52	%
Oil, natural gas and NGLs (MMcfe)	73,508		70,095		3,413			5	%
Revenue data (in thousands): (1)
Oil revenue	$	324,105	$	404,477	$	(80,372	)	(20	)%
Natural gas revenue	72,611		133,183		(60,572		)	(45	)%
NGLs revenue	29,379		64,920		(35,541		)	(55	)%
Total oil, natural gas and NGL revenue	$	426,095	$	602,580	$	(176,485	)	(29	)%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	48.74	$	98.03	$	(49.29	)	(50	)%
Natural gas (per Mcf)	1.94		3.92		(1.98		)	(51	)%
NGLs (per Bbl)	13.10		44.10		(31.00		)	(70	)%
Oil, natural gas and NGLs (per Mcfe)	4.34		8.85		(4.51		)	(51	)%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	69.48	$	95.67	$	(26.19	)	(27	)%
Natural gas (per Mcf)	2.26		3.71		(1.45		)	(39	)%
NGLs (per Bbl)	13.10		44.10		(31.00		)	(70	)%
Oil, natural gas and NGLs (per Mcfe)	5.80		8.60		(2.80		)	(33	)%
Expenses (per Mcfe):
Lease operating expenses	$	1.08	$	2.00	$	(0.92	)	(46	)%
Transportation, processing and gathering expenses	0.76		0.65		0.11			17	%
SG&A expenses (2)	0.72		0.70		0.02			3	%
DD&A expense on oil and gas properties	3.03		3.61		(0.58		)	(16	)%

(1) Includes the cash settlement of effective hedging contracts

(2) Excludes incentive compensation expense

Net Income. During the three months ended September 30, 2015, we reported a net loss totaling approximately $292.0 million, or $5.28 per share, compared to a net loss for the three months ended September 30, 2014 of $29.4 million, or $0.54 per share. During the nine months ended September 30, 2015, we reported a net loss totaling approximately $772.3 million, or $13.98 per share, compared to net income for the nine months ended September 30, 2014 of $1.0 million, or $0.02 per share. All per share amounts are on a diluted basis.

We follow the full cost method of accounting for oil and gas properties. At September 30, 2015, we recognized a ceiling test write-down of our U.S. oil and gas properties totaling $295.7 million. At June 30, 2015, we recognized ceiling test write-downs of our U.S. and Canadian oil and gas properties totaling $224.3 million. At March 31, 2015, we recognized a ceiling test write-down of our U.S. oil and gas properties totaling $491.4 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 nine month periods’ results was also due to the following components:

Production. During the three months ended September 30, 2015, total production volumes increased to 22.0 Bcfe compared to 21.8 Bcfe produced during the comparable 2014 period. Oil production during the three months ended September 30, 2015 totaled approximately 1,509,000 Bbls compared to 1,329,000 Bbls produced during the comparable 2014 period. Natural gas production totaled 8.3 Bcf during the three months ended September 30, 2015 compared to 10.9 Bcf during the comparable 2014 period. NGL production during the three months ended September 30, 2015 totaled approximately 765,000 Bbls compared to 495,000 Bbls produced during the comparable 2014 period.

During the nine months ended September 30, 2015, total production volumes increased to 73.5 Bcfe compared to 70.1 Bcfe produced during the comparable 2014 period, representing a 5% increase. Oil production during the nine months ended September 30, 2015 totaled approximately 4,665,000 Bbls compared to 4,228,000 Bbls produced during the comparable 2014 period. Natural gas

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production totaled 32.1 Bcf during the nine months ended September 30, 2015 compared to 35.9 Bcf during the comparable 2014 period. NGL production during the nine months ended September 30, 2015 totaled approximately 2,242,000 Bbls compared to 1,472,000 Bbls produced during the comparable 2014 period.

During the three months ended June 30, 2015, we realized increases to our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units. Although we recognized approximately 1.7 Bcfe of incremental production volumes associated with increased interests, net operating income for the affected wells was only minimally impacted due to depressed commodity prices. The increase in oil volumes during the nine months ended September 30, 2015 was also attributable to production from our deepwater Cardona wells, which began producing late in the fourth quarter of 2014. These increases in production volumes were partially offset by decreases in production resulting from the divestitures of certain of our non-core GOM conventional shelf properties during 2014. Production volumes for the three months ended September 30, 2015 were also negatively impacted by the shut-in of the Mary field in Appalachia.

Prices. Prices realized during the three months ended September 30, 2015 averaged $69.59 per Bbl of oil, $2.09 per Mcf of natural gas and $7.82 per Bbl of NGLs, or 27% lower, on an Mcfe basis, than average realized prices of $93.15 per Bbl of oil, $2.77 per Mcf of natural gas and $42.45 per Bbl of NGLs during the comparable 2014 period. Prices realized during the nine months ended September 30, 2015 averaged $69.48 per Bbl of oil, $2.26 per Mcf of natural gas and $13.10 per Bbl of NGLs, or 33% lower, on an Mcfe basis, than average realized prices of $95.67 per Bbl of oil, $3.71 per Mcf of natural gas and $44.10 per Bbl of NGLs during the comparable 2014 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 $0.44 per Mcf and increased our average realized oil price by $24.08 per Bbl during the three months ended September 30, 2015. During the three months ended September 30, 2014, our effective hedging transactions had a minimal impact on average realized natural gas prices and decreased our average realized oil price by $1.02 per Bbl. During the nine months ended September 30, 2015 our effective hedging transactions increased our average realized natural gas price by $0.32 per Mcf and increased our average realized oil price by $20.74 per Bbl. During the nine months ended September 30, 2014, our effective hedging transactions decreased our average realized natural gas price by $0.21 per Mcf and decreased our average realized oil price by $2.36 per Bbl.

Revenue. Oil, natural gas and NGL revenue was $128.4 million during the three months ended September 30, 2015 compared to $175.0 million during the comparable period of 2014. For the nine months ended September 30, 2015 and 2014, oil, natural gas and NGL revenue totaled $426.1 million and $602.6 million, respectively. The decrease in total revenue for the three and nine months ended September 30, 2015 was primarily due to a 27% and 33% decrease, respectively, in average realized prices from the comparable periods of 2014. The decreases were also attributable to the divestitures of certain non-core GOM conventional shelf properties during 2014.

Derivative Income/Expense. Net derivative income for the three months ended September 30, 2015 totaled $2.4 million, comprised of $5.3 million of income from cash settlements and $2.9 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the three months ended September 30, 2014, net derivative income totaled $5.8 million, comprised of $0.7 million of income from cash settlements and $5.1 million of non-cash income resulting from changes in the fair value of unsettled derivative instruments. Net derivative income for the nine months ended September 30, 2015 totaled $4.9 million, comprised of $15.7 million of income from cash settlements and $10.8 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the nine months ended September 30, 2014, net derivative income totaled $2.7 million, comprised of $0.2 million of income from cash settlements and $2.5 million of non-cash income resulting from changes in the fair value of unsettled derivative instruments.

Expenses. Lease operating expenses during the three months ended September 30, 2015 and 2014 totaled $24.2 million and $43.6 million, respectively. For the nine months ended September 30, 2015 and 2014, lease operating expenses totaled $79.3 million and $139.9 million, respectively. On a unit of production basis, lease operating expenses were $1.10 per Mcfe and $2.00 per Mcfe for the three months ended September 30, 2015 and 2014, respectively, and $1.08 per Mcfe and $2.00 per Mcfe for the nine months ended September 30, 2015 and 2014, respectively. The decrease in lease operating expenses during the three and nine months ended September 30, 2015 was primarily attributable to the divestitures of certain non-core GOM conventional shelf properties during 2014 as well as service cost reductions and operating efficiencies.

Transportation, processing and gathering expenses during the three months ended September 30, 2015 and 2014 totaled $18.2 million and $16.7 million, respectively, or $0.83 per Mcfe and $0.77 per Mcfe, respectively. For the nine months ended September 30, 2015 and 2014, transportation, processing and gathering expenses totaled $55.9 million and $45.4 million, respectively, or $0.76 per Mcfe and $0.65 per Mcfe, respectively. The increase was attributable to higher gas, NGL and condensate volumes in Appalachia, where processing and gathering costs are higher. Additionally, the results for the three months ended September 30, 2015 included a

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$2.9 million accrual for a potential liability associated with an ongoing regulatory examination relating to processing fees for our GOM production.

Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the three months ended September 30, 2015 totaled $60.8 million compared to $79.2 million during the comparable period of 2014. For the nine months ended September 30, 2015 and 2014, DD&A expense totaled $222.8 million and $252.9 million, respectively. On a unit of production basis, DD&A expense was $2.77 per Mcfe and $3.63 per Mcfe during the three months ended September 30, 2015 and 2014, respectively. For the nine months ended September 30, 2015 and 2014, DD&A expense, on a unit of production basis, was $3.03 per Mcfe and $3.61 per Mcfe, respectively. The decrease in DD&A from 2014 was primarily due to the ceiling test write-downs of our oil and gas properties.

SG&A expenses (exclusive of incentive compensation) for the three months ended September 30, 2015 were $19.6 million compared to $16.3 million for the three months ended September 30, 2014. For the nine months ended September 30, 2015 and 2014, SG&A expenses (exclusive of incentive compensation) totaled $53.0 million and $49.3 million, respectively. On a unit of production basis, SG&A expenses were $0.89 per Mcfe and $0.75 per Mcfe for the three months ended September 30, 2015 and 2014, respectively. For the nine months ended September 30, 2015 and 2014, SG&A expenses, on a unit of production basis, were $0.72 per Mcfe and $0.70 per Mcfe, respectively. The increase in SG&A expenses for the three months ended September 30, 2015 related primarily to $1.8 million in severance payments made in conjunction with a reduction of our workforce and $2.1 million of lease termination charges associated with the early termination of an office lease. SG&A expenses for the nine months ended September 30, 2015 included approximately $3.7 million in severance payments associated with the reduction in our workforce.

For the three months ended September 30, 2015 and 2014, incentive compensation expense totaled $0.8 million and $3.1 million, respectively. For the nine months ended September 30, 2015 and 2014, incentive compensation expense totaled $3.6 million and $10.1 million, respectively. These amounts related to the accrual of estimated incentive compensation bonuses, which are calculated based on the projected achievement of certain strategic objectives for each fiscal year.

Interest expense for the three months ended September 30, 2015 totaled $10.9 million, net of $10.3 million of capitalized interest, compared to interest expense of $10.3 million, net of $10.8 million of capitalized interest, during the comparable 2014 period. For the nine months ended September 30, 2015, interest expense totaled $31.7 million, net of $31.9 million of capitalized interest, compared to interest expense of $28.6 million, net of $34.8 million of capitalized interest, during the comparable 2014 period. The increase in interest expense was primarily the result of a decrease in the amount of interest capitalized to oil and gas properties.

For the nine months ended September 30, 2015 and 2014, we recorded an income tax (benefit) provision of $(280.8) million and $3.6 million, respectively. The income tax benefit recorded for the nine months ended September 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 over the past four quarters, we determined 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 $96.5 million valuation allowance against a portion of our deferred tax assets in the third quarter of 2015. 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.

Off-Balance Sheet Arrangements

None.

Recent Accounting Developments

None.

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 represents one million barrels of oil equivalent. 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 nine months ended September 30, 2015, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $4.4 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.

On October 15, 2015, our board of directors approved a change in the amount of our estimated production quantities that can be hedged for any given year, increasing it from 50% to 60%. We believe that our hedging positions as of November 3, 2015 have hedged approximately 47% of our estimated 2015 production from estimated proved reserves and 21% 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 3 – 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 2014 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 $1,075 million at September 30, 2015, all of which bears interest at fixed rates. The $1,075 million of fixed-rate debt is comprised of $300 million face value of the 2017 Convertible Notes and $775 million of the 2022 Notes.

Our bank credit facility is subject to an adjustable interest rate. 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. We had no outstanding borrowings under our bank credit facility as of September 30, 2015. If we borrow funds under our bank credit facility, we may be subject to increased sensitivity to interest rate movements.

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 September 30, 2015 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 September 30, 2015 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. 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. Stone engaged counsel and removed the cases to federal court. The plaintiffs opposed removal. All four cases have been remanded to Louisiana state court. Stone and other defendants filed peremptory and dilatory exceptions, which are pending. Stone is actively investigating and evaluating the allegations.

On July 26, 2012, we received a 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 our Vermillion Block 255 Platform H in April 2012. We believe that the conditions observed were not actually violations of applicable rules and accordingly initiated discussions with BSEE to resolve the matter. Notwithstanding these discussions, by “Reviewing Officer’s Final Decision” dated July 9, 2013, BSEE assessed a penalty against Stone of $200,000 based on $25,000 per day for eight days of alleged improper venting of gas at the platform. On administrative appeal, the Interior Board of Land Appeals affirmed the penalty. Stone's appeal to the Director of the Department of the Interior Office of Hearings and Appeals is pending. We do not believe that this proceeding will have a material adverse effect on our financial condition or results of operations.

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. In September 2014, Stone sold its interest in the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”), and PADEP approved the transfer on November 24, 2014, after Stone’s receipt of the NOV. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time. Southwestern is conducting remediation activities at the well site, and Stone continues to monitor those activities.

Also on November 17, 2014, the Environmental Protection Agency (“EPA”) issued two administrative compliance orders relating, respectively, to Stone’s Conley and Tuttle Impoundment Sites in West Virginia. The EPA compliance orders (1) allege that Stone placed fill material in jurisdictional waters without first obtaining a Clean Water Act permit and (2) order Stone to submit a wetland and stream delineation report. On December 8, 2014, Stone received a request from the EPA for additional information about the sites. Stone responded to this request and submitted site delineations. Stone settled the enforcements action for the Conley and Tuttle Impoundment Sites for $135,647 and $141,245, respectively. The EPA has also approved Stone’s wetland and stream delineation report. A Final Consent Agreement and Order was issued September 17, 2015 and Stone's payment was released. Stone continues to work with the EPA on a restoration plan.

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

There have been no material changes with respect to Stone’s risk factors previously reported in Part I, Item 1A, of our 2014 Annual Report on Form 10-K.

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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 September 30, 2015: 

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
July 1 - July 31, 2015	4,873	$	11.92	—
August 1 - August 31, 2015	—	—		—
September 1 - September 30, 2015	—	—		—
	4,873	$	11.92	—	$	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 repurchase program during the three months ended September 30, 2015.

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)).
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)).
*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:	November 5, 2015	By:	/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)).
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)).
*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.

36