Stone Energy (SGY) 10-Q 2016 Q1 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 March 31, 2016

or

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

For the transition period from                      to                     

Commission File Number: 1-12074

__________________________________________________________ 

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________

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 May 4, 2016, there were 56,864,607 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 March 31, 2016 and December 31, 2015	1
	Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2016 and 2015	2
	Condensed Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended March 31, 2016 and 2015	3
	Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2016 and 2015	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	30
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 6.	Exhibits	33
	Signatures	34
	Exhibit Index	35

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)

	March 31, 2016			December 31, 2015
	(Unaudited)			(Note 1)
Assets
Current assets:
Cash and cash equivalents	$	367,134		$	10,759
Accounts receivable	42,185			48,031
Fair value of derivative contracts	30,222			38,576
Current income tax receivable	46,174			46,174
Inventory	535			535
Other current assets	6,531			6,346
Total current assets	492,781			150,421
Oil and gas properties, full cost method of accounting:
Proved	9,481,859			9,375,898
Less: accumulated depreciation, depletion and amortization	(8,796,412		)	(8,603,955		)
Net proved oil and gas properties	685,447			771,943
Unevaluated	421,429			440,043
Other property and equipment, net	28,667			29,289
Other assets, net	18,257			18,473
Total assets	$	1,646,581		$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	38,200		$	82,207
Undistributed oil and gas proceeds	3,875			5,992
Accrued interest	22,901			9,022
Asset retirement obligations	23,465			21,291
Current portion of long-term debt	459,201			—
Other current liabilities	32,671			40,712
Total current liabilities	580,313			159,224
Long-term debt	1,063,090			1,060,955
Asset retirement obligations	209,848			204,575
Other long-term liabilities	18,329			25,204
Total liabilities	1,871,580			1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 150,000,000 shares; issued 55,806,817 and 55,302,325 shares, respectively	558			553
Treasury stock (16,582 shares, at cost)	(860		)	(860		)
Additional paid-in capital	1,650,969			1,648,189
Accumulated deficit	(1,894,407		)	(1,705,623		)
Accumulated other comprehensive income	18,741			17,952
Total stockholders’ equity	(224,999		)	(39,789		)
Total liabilities and stockholders’ equity	$	1,646,581		$	1,410,169

 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 March 31,
	2016			2015
Operating revenue:
Oil production	$	60,275		$	107,507
Natural gas production	15,173			28,337
Natural gas liquids production	4,735			12,366
Other operational income	356			2,160
Derivative income, net	138			3,128
Total operating revenue	80,677			153,498
Operating expenses:
Lease operating expenses	19,547			27,577
Transportation, processing and gathering expenses	841			17,703
Production taxes	481			2,515
Depreciation, depletion and amortization	61,558			86,422
Write-down of oil and gas properties	129,204			491,412
Accretion expense	9,983			6,409
Salaries, general and administrative expenses	13,707			17,007
Incentive compensation expense	4,979			1,563
Other operational expenses	12,527			84
Total operating expenses	252,827			650,692
Loss from operations	(172,150		)	(497,194		)
Other (income) expenses:
Interest expense	15,241			10,365
Interest income	(114		)	(122		)
Other income	(298		)	(143		)
Other expense	2			—
Total other expenses	14,831			10,100
Loss before income taxes	(186,981		)	(507,294		)
Provision (benefit) for income taxes:
Current	(1,074		)	—
Deferred	2,877			(179,906		)
Total income taxes	1,803			(179,906		)
Net loss	$	(188,784	)	$	(327,388	)
Basic loss per share	$	(3.39	)	$	(5.93	)
Diluted loss per share	$	(3.39	)	$	(5.93	)
Average shares outstanding	55,713			55,181
Average shares outstanding assuming dilution	55,713			55,181

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 March 31,
	2016			2015
Net loss	$	(188,784	)	$	(327,388	)
Other comprehensive loss, net of tax effect:
Derivatives	(5,285		)	(8,858		)
Foreign currency translation	6,074			(3,645		)
Comprehensive loss	$	(187,995	)	$	(339,891	)

The accompanying notes are an integral part of this statement.

3

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2016			2015
Cash flows from operating activities:
Net loss	$	(188,784	)	$	(327,388	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	61,558			86,422
Write-down of oil and gas properties	129,204			491,412
Accretion expense	9,983			6,409
Deferred income tax provision (benefit)	2,877			(179,906		)
Settlement of asset retirement obligations	(4,667		)	(17,145		)
Non-cash stock compensation expense	2,312			2,640
Non-cash derivative expense	192			1,511
Non-cash interest expense	4,635			4,318
Other non-cash expense	6,081			—
Change in current income taxes	(1,074		)	7,188
Decrease in accounts receivable	5,845			8,206
(Increase) decrease in other current assets	(185		)	1,883
Decrease in accounts payable	(2,138		)	(8,657		)
Increase in other current liabilities	3,898			6,889
Other	(298		)	(260		)
Net cash provided by operating activities	29,439			83,522
Cash flows from investing activities:
Investment in oil and gas properties	(129,859		)	(169,895		)
Investment in fixed and other assets	(496		)	(662		)
Change in restricted funds	1,045			177,642
Net cash (used in) provided by investing activities	(129,310		)	7,085
Cash flows from financing activities:
Proceeds from bank borrowings	477,000			5,000
Repayments of bank borrowings	(20,000		)	(5,000		)
Repayments of building loan	(95		)	—
Net payments for share-based compensation	(650		)	(2,991		)
Net cash provided by (used in) financing activities	456,255			(2,991		)
Effect of exchange rate changes on cash	(9		)	24
Net change in cash and cash equivalents	356,375			87,640
Cash and cash equivalents, beginning of period	10,759			74,488
Cash and cash equivalents, end of period	$	367,134		$	162,128

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 March 31, 2016 and for the three month periods ended March 31, 2016 and 2015 are unaudited and reflect all adjustments (consisting only of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim periods. The condensed consolidated balance sheet as of December 31, 2015 has been derived from the audited financial statements as of that date contained in our Annual Report on Form 10-K for the year ended December 31, 2015 (our “2015 Annual Report on Form 10-K”). The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations, contained in our 2015 Annual Report on Form 10-K. The results of operations for the three month period ended March 31, 2016 are not necessarily indicative of future financial results.

Note 2 – Going Concern

The accompanying condensed consolidated financial statements have been prepared assuming the company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these condensed consolidated financial statements. As such, the accompanying condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the company be unable to continue as a going concern.

The level of our indebtedness of $1,544 million and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. At March 31, 2016, we were in compliance with all of our financial covenants under our bank credit facility and the indentures governing our outstanding notes. However, given the lower commodity prices and our reduced hedged position in 2016, we anticipate that we will exceed the Consolidated Funded Debt to consolidated EBITDA financial covenant of 3.75 to 1 set forth in our bank credit agreement at the end of the second quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments. These conditions raise substantial doubt about our ability to continue as a going concern.

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

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

5

Note 3 – Earnings Per Share

The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods:

	Three Months Ended March 31,
	2016			2015
	(In thousands, except per share data)
Income (numerator):
Basic:
Net loss	$	(188,784	)	$	(327,388	)
Net income attributable to participating securities	—			—
Net loss attributable to common stock - basic	$	(188,784	)	$	(327,388	)
Diluted:
Net loss	$	(188,784	)	$	(327,388	)
Net income attributable to participating securities	—			—
Net loss attributable to common stock - diluted	$	(188,784	)	$	(327,388	)
Weighted average shares (denominator):
Weighted average shares - basic	55,713			55,181
Dilutive effect of stock options	—			—
Dilutive effect of convertible notes	—			—
Weighted average shares - diluted	55,713			55,181
Basic loss per share	$	(3.39	)	$	(5.93	)
Diluted loss per share	$	(3.39	)	$	(5.93	)

All outstanding stock options were considered antidilutive during the three months ended March 31, 2016 (approximately 129,000 shares) and during the three months ended March 31, 2015 (approximately 204,000 shares) because we had net losses for such periods.

During the three months ended March 31, 2016 and 2015, approximately 504,000 shares and 370,000 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors.

For the three months ended March 31, 2016 and 2015, the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such periods. For the three months ended March 31, 2016 and 2015, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 5 – Debt) and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in Note 5 – Debt), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.

Note 4 – Derivative Instruments and Hedging Activities

Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.

The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, it is recorded as either an asset or liability measured at fair value and subsequent changes in the 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.

6

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

All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an "investment grade" credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At May 4, 2016, two counterparties accounted for approximately 86% of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility. 

The following tables illustrate our derivative positions for calendar year 2016 as of May 4, 2016:

	Fixed-Price Swaps (NYMEX)
	Natural Gas		Oil
	Daily Volume (MMBtus/d)	Swap Price ($)	Daily Volume (Bbls/d)	Swap Price ($)
2016	10,000	4.110	1,000	49.75
2016	10,000	4.120	1,000	52.78
2016			1,000	90.00

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

We previously discontinued hedge accounting for certain 2015 natural gas contracts, as it became no longer probable that our Gulf of Mexico ("GOM") natural gas production would be sufficient to cover the GOM volumes hedged. Additionally, a small portion of our cash flow hedges are typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products are not 100% correlative to changes in the underlying price basis indicative in the derivative contract. At March 31, 2016, we had accumulated other comprehensive income of $18.7 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of March 31, 2016. The $18.7 million of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.

Derivatives qualifying as hedging instruments:

The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at March 31, 2016 and December 31, 2015:

7

Fair Value of Derivatives Qualifying as Hedging Instruments at
March 31, 2016
(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	$	30.2	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	—		Long-term liabilities: Fair value of derivative contracts	—
		$	30.2		$	—
Fair Value of Derivatives Qualifying as Hedging Instruments at
December 31, 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	$	38.6	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	—		Long-term liabilities: Fair value of derivative contracts	—
		$	38.6		$	—

The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three month periods ended March 31, 2016 and 2015:

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended March 31, 2016 and 2015
(In millions)
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives				Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)					Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2016		2015		Location	2016		2015		Location	2016		2015
Commodity contracts	$	4.6	$	22.9	Operating revenue - oil/natural gas production	$	12.8	$	36.8	Derivative income (expense), net	$	0.1	$	0.9
Total	$	4.6	$	22.9		$	12.8	$	36.8		$	0.1	$	0.9

(a) For the three months ended March 31, 2016, effective hedging contracts increased oil revenue by $9.3 million and increased natural gas revenue by $3.5 million. For the three months ended March 31, 2015, effective hedging contracts increased oil revenue by $34.0 million and increased natural gas revenue by $2.8 million.

Derivatives not qualifying as hedging instruments:

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

8

Gain (Loss) Recognized in Derivative Income (Expense) (In millions)
	Three Months Ended March 31,
Description	2016		2015
Commodity contracts:
Cash settlements	$	—	$	3.1
Change in fair value	—		(0.9		)
Total gain on non-qualifying hedges	$	—	$	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. As of March 31, 2016 and December 31, 2015, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

Note 5 – Debt

Our debt balances (net of related unamortized discounts and debt issuance costs) as of March 31, 2016 and December 31, 2015 were as follows:

	March 31, 2016			December 31, 2015
	(In millions)
1 3⁄4% Senior Convertible Notes due 2017	$	283.5		$	279.3
7 1⁄2% Senior Notes due 2022	770.2			770.0
Revolving credit facility	457.0			—
4.20% Building Loan	11.6			11.7
Total debt	1,522.3			1,061.0
Less: current portion of long-term debt	(459.2		)	—
Long-term debt	$	1,063.1		$	1,061.0

Current Portion of Long-Term Debt. As of March 31, 2016, the current portion of long-term debt of $459.2 million consisted of $283.5 million of 2017 Convertible Notes, $175.3 million of outstanding borrowings under the bank credit facility (our borrowing base deficiency) and $0.4 million of principal payments due within one year on the Building Loan.

Revolving Credit Facility. On June 24, 2014, we entered into an amended and 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 March 31, 2016, we had a $500 million borrowing base under the credit facility, with $457 million of outstanding borrowings and $19.2 million of outstanding letters of credit, leaving $23.8 million of availability under the bank credit facility. The weighted average interest rate under the bank credit facility was approximately 3.5% at March 31, 2016. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of March 31, 2016, the bank credit facility was guaranteed by Stone Energy Offshore, L.L.C. (“Stone Offshore”), SEO A LLC and SEO B LLC (collectively, the “Guarantor Subsidiaries”).

The borrowing base under the bank credit facility is redetermined semi-annually, typically by May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank credit facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. On April 13, 2016, we received notice that our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly

9

installments. We have not taken any action or made an election of actions to be taken to cure the borrowing base deficiency. The $175.3 million borrowing base deficiency is classified as a current liability at March 31, 2016.

The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage, and grant a security interest in, our oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Interest on loans under the bank credit facility is calculated using the London Interbank Offering (“LIBOR”) rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%.

Under the financial covenants of the 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 2.5 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 March 31, 2016.

2017 Convertible Notes. On March 6, 2012, we issued in a private offering $300 million in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes are convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, based on an initial conversion rate of 23.4449 shares of our common stock per $1,000 principal amount of 2017 Convertible Notes, which corresponds to an initial conversion price of approximately $42.65 per share of our common stock. On March 31, 2016, our closing share price was $0.79 per share. 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), and interest is payable on the 2017 Convertible Notes each March 1and September 1. On the maturity date, each holder will be entitled to receive $1,000 in cash for each $1,000 in principal amount of 2017 Convertible Notes, together with any accrued and unpaid interest to, but excluding, the maturity date.

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 March 31, 2016, the carrying amount of the liability component of the 2017 Convertible Notes of $283.5 million was classified as a current liability. During the three months ended March 31, 2016, we recognized $3.9 million of interest expense for the amortization of the discount and $0.4 million of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three months ended March 31, 2015, we recognized $3.6 million of interest expense for the amortization of the discount and $0.3 million of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During each of the three month periods ended March 31, 2016 and 2015, we recognized $1.3 million of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

10

Note 6 – Asset Retirement Obligations

The change in our asset retirement obligations during the three months ended March 31, 2016 is set forth below:

	Three Months Ended March 31, 2016
	(In millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	225.9
Liabilities incurred	2.1
Liabilities settled	(4.7		)
Accretion expense	10.0
Asset retirement obligations as of the end of the period, including current portion	$	233.3

Note 7 – Income Taxes

As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of March 31, 2016, our valuation allowance totaled $245.5 million. Our effective tax rate for the three months ended March 31, 2016 was 1.0%. This percentage differed from the federal statutory rate of 35.0% primarily due to the establishment of valuation allowances against deferred tax assets. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities. We had a current income tax receivable of $46.2 million at March 31, 2016, which relates to expected tax refunds from the carryback of net operating losses to previous tax years.

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 March 31, 2016 and December 31, 2015, we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call portion of the collar. For a more detailed description of our derivative instruments, see Note 4 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

We had no liabilities measured at fair value on a recurring basis at March 31, 2016 and December 31, 2015. The following tables present our assets that are measured at fair value on a recurring basis at March 31, 2016 and December 31, 2015:

	Fair Value Measurements at
	March 31, 2016
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)	$	8.5	$	8.5	$	—	$	—
Derivative contracts	30.2		—		28.8		1.4
Total	$	38.7	$	8.5	$	28.8	$	1.4

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	Fair Value Measurements at
	December 31, 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)	$	8.5	$	8.5	$	—	$	—
Derivative contracts	38.6		—		36.6		2.0
Total	$	47.1	$	8.5	$	36.6	$	2.0

The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2016.

	Hedging Contracts, net
	(In millions)
Balance as of January 1, 2016	$	2.0
Total gains/(losses) (realized or unrealized):
Included in earnings	1.0
Included in other comprehensive income	(0.5		)
Purchases, sales, issuances and settlements	(1.1		)
Transfers in and out of Level 3	—
Balance as of March 31, 2016	$	1.4
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at March 31, 2016	$	—

The fair value of cash and cash equivalents approximated book value at March 31, 2016 and December 31, 2015. As of March 31, 2016 and December 31, 2015, the fair value of the liability component of the 2017 Convertible Notes was approximately $225.3 million and $217.1 million, respectively. As of March 31, 2016 and December 31, 2015, the fair value of the 7 1⁄2% Senior Notes due 2022 (the “2022 Notes”) was approximately $209.3 million and $271.3 million, respectively.

The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see Note 5 – Debt) at inception, March 31, 2016 and December 31, 2015. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

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Note 9 – Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss) by component for the three months ended March 31, 2016 and 2015 were as follows (in millions):

	Cash Flow Hedges			Foreign Currency Items			Total
Three Months Ended March 31, 2016
Beginning balance, net of tax	$	24.0		$	(6.0	)	$	18.0
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	4.6			—			4.6
Income tax effect	(1.6		)	—			(1.6		)
Net of tax	3.0			—			3.0
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	12.8			—			12.8
Other operational expenses	—			(6.0		)	(6.0		)
Income tax effect	(4.5		)	—			(4.5		)
Net of tax	8.3			(6.0		)	2.3
Other comprehensive income (loss), net of tax	(5.3		)	6.0			0.7
Ending balance, net of tax	$	18.7		$	—		$	18.7

	Cash Flow Hedges			Foreign Currency Items			Total
Three Months Ended March 31, 2015
Beginning balance, net of tax	$	86.8		$	(3.5	)	$	83.3
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	22.9			—			22.9
Foreign currency translations	—			(3.6		)	(3.6		)
Income tax effect	(8.2		)	—			(8.2		)
Net of tax	14.7			(3.6		)	11.1
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	36.8			—			36.8
Income tax effect	(13.2		)	—			(13.2		)
Net of tax	23.6			—			23.6
Other comprehensive loss, net of tax	(8.9		)	(3.6		)	(12.5		)
Ending balance, net of tax	$	77.9		$	(7.1	)	$	70.8

During the three months ended March 31, 2016, we reclassified approximately $6.0 million of losses related to cumulative foreign currency translation adjustments, from accumulated other comprehensive income into other operational expenses, upon the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC.

Note 10 – Investment in Oil and Gas Properties

Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows. At March 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $128.9 million based on twelve-month average prices, net of applicable differentials, of $46.72 per Bbl of oil, $2.01 per Mcf of natural gas and $13.65 per Bbl of natural gas liquids ("NGLs"), as compared to December 31, 2015 twelve-month average prices, net of applicable differentials, of $51.16 per Bbl of oil, $2.19 per Mcf of natural gas and $16.40 per Bbl of NGLs. At March 31, 2016, the write-down of oil and gas properties also included $0.3 million related

13

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

Note 11 – Other Operational Expenses

Included in other operational expenses for the three months ended March 31, 2016 is a $6.0 million loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See Note 9 - Accumulated Other Comprehensive Income (Loss). Also included in other operational expenses for the three months ended March 31, 2016 are approximately $6.1 million of rig subsidy charges related to the farm out of the ENSCO 8503 deep water drilling rig and stacking charges related to the Saxon Appalachian rig.

Note 12 – Commitments and Contingencies

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management ("BOEM") stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s current guidance to lessees. BOEM's notice letters indicate the amount of Stone's supplemental bonding needs could be as much as $565 million. We are in discussions with BOEM to reduce the amount of the supplemental bonding or other forms of financial assurance that the agency may require and the timing of when such bonds or financial assurances may need to be provided. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations. We currently have approximately $223 million posted in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. Our proposed tailored plan provides for posting some incremental financial assurances in favor of BOEM and discussions on the approval and implementation of this plan are ongoing.

Note 13 – Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-02, "Leases (Topic 842)" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements.

In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.

Note 14 - Subsequent Event

On April 29, 2016, we were notified by the New York Stock Exchange (“NYSE”) that we were not in compliance with the NYSE's continued listing requirements, as the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price for continued listing on the NYSE under Rule 802.01C of the NYSE Listed Company Manual. Under the NYSE’s rules, we have six months following receipt of the notification to regain compliance with the minimum share price requirement.

Note 15 – Guarantor Financial Statements

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

14

CONDENSED CONSOLIDATING BALANCE SHEET

MARCH 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	367,133		$	1		$	—		$	—		$	367,134
Accounts receivable	57,106			38,476			885			(54,282		)	42,185
Fair value of derivative contracts	—			30,222			—			—			30,222
Current income tax receivable	46,174			—			—			—			46,174
Inventory	535			—			—			—			535
Other current assets	6,531			—			—			—			6,531
Total current assets	477,479			68,699			885			(54,282		)	492,781
Oil and gas properties, full cost method:
Proved	1,891,423			7,544,791			45,645			—			9,481,859
Less: accumulated DD&A	(1,891,423		)	(6,859,344		)	(45,645		)	—			(8,796,412		)
Net proved oil and gas properties	—			685,447			—			—			685,447
Unevaluated	261,724			159,705			—			—			421,429
Other property and equipment, net	28,667			—			—			—			28,667
Other assets, net	17,460			797			—			—			18,257
Investment in subsidiary	614,540			—			—			(614,540		)	—
Total assets	$	1,399,870		$	914,648		$	885		$	(668,822	)	$	1,646,581
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	24,915		$	67,567		$	—		$	(54,282	)	$	38,200
Undistributed oil and gas proceeds	2,800			1,075			—			—			3,875
Accrued interest	22,901			—			—			—			22,901
Asset retirement obligations	—			23,465			—			—			23,465
Current portion of long-term debt	459,201			—			—			—			459,201
Other current liabilities	32,335			336			—			—			32,671
Total current liabilities	542,152			92,443			—			(54,282		)	580,313
Long-term debt	1,063,090			—			—			—			1,063,090
Asset retirement obligations	1,298			208,550			—			—			209,848
Other long-term liabilities	18,329			—			—			—			18,329
Total liabilities	1,624,869			300,993			—			(54,282		)	1,871,580
Commitments and contingencies
Stockholders’ equity:
Common stock	558			—			—			—			558
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,650,969			1,344,577			109,077			(1,453,654		)	1,650,969
Accumulated deficit	(1,894,407		)	(749,663		)	(108,192		)	857,855			(1,894,407		)
Accumulated other comprehensive income	18,741			18,741			—			(18,741		)	18,741
Total stockholders’ equity	(224,999		)	613,655			885			(614,540		)	(224,999		)
Total liabilities and stockholders’ equity	$	1,399,870		$	914,648		$	885		$	(668,822	)	$	1,646,581

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CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2015

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,681		$	2		$	1,076		$	—		$	10,759
Accounts receivable	10,597			39,190			—			(1,756		)	48,031
Fair value of derivative contracts	—			38,576			—			—			38,576
Current income tax receivable	46,174			—			—			—			46,174
Inventory	535			—			—			—			535
Other current assets	6,313			—			33			—			6,346
Total current assets	73,300			77,768			1,109			(1,756		)	150,421
Oil and gas properties, full cost method:
Proved	1,875,152			7,458,262			42,484			—			9,375,898
Less: accumulated DD&A	(1,874,622		)	(6,686,849		)	(42,484		)	—			(8,603,955		)
Net proved oil and gas properties	530			771,413			—			—			771,943
Unevaluated	253,308			186,735			—			—			440,043
Other property and equipment, net	29,289			—			—			—			29,289
Other assets, net	16,612			826			1,035			—			18,473
Investment in subsidiary	745,033			—			1,088			(746,121		)	—
Total assets	$	1,118,072		$	1,036,742		$	3,232		$	(747,877	)	$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	16,063		$	67,901		$	—		$	(1,757	)	$	82,207
Undistributed oil and gas proceeds	5,216			776			—			—			5,992
Accrued interest	9,022			—			—			—			9,022
Asset retirement obligations	—			20,400			891			—			21,291
Other current liabilities	40,161			551			—			—			40,712
Total current liabilities	70,462			89,628			891			(1,757		)	159,224
Long-term debt	1,060,955			—			—			—			1,060,955
Asset retirement obligations	1,240			203,335			—			—			204,575
Other long-term liabilities	25,204			—			—			—			25,204
Total liabilities	1,157,861			292,963			891			(1,757		)	1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock	553			—			—			—			553
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,648,189			1,344,577			109,795			(1,454,372		)	1,648,189
Accumulated deficit	(1,705,623		)	(624,824		)	(95,306		)	720,130			(1,705,623		)
Accumulated other comprehensive income (loss)	17,952			24,026			(12,148		)	(11,878		)	17,952
Total stockholders’ equity	(39,789		)	743,779			2,341			(746,120		)	(39,789		)
Total liabilities and stockholders’ equity	$	1,118,072		$	1,036,742		$	3,232		$	(747,877	)	$	1,410,169

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	61		$	60,214		$	—		$	—		$	60,275
Natural gas production	2,467			12,706			—			—			15,173
Natural gas liquids production	1,134			3,601			—			—			4,735
Other operational income	356			—			—			—			356
Derivative income, net	—			138			—			—			138
Total operating revenue	4,018			76,659			—			—			80,677
Operating expenses:
Lease operating expenses	2,728			16,806			13			—			19,547
Transportation, processing and gathering expenses	1,546			(705		)	—			—			841
Production taxes	259			222			—			—			481
Depreciation, depletion and amortization	8,594			52,964			—			—			61,558
Write-down of oil and gas properties	9,324			119,531			349			—			129,204
Accretion expense	58			9,925			—			—			9,983
Salaries, general and administrative expenses	13,907			(200		)	—			—			13,707
Incentive compensation expense	4,979			—			—			—			4,979
Other operational expenses	6,109			337			6,081			—			12,527
Total operating expenses	47,504			198,880			6,443			—			252,827
Loss from operations	(43,486		)	(122,221		)	(6,443		)	—			(172,150		)
Other (income) expenses:
Interest expense	15,241			—			—			—			15,241
Interest income	(114		)	—			—			—			(114		)
Other income	(39		)	(259		)	—			—			(298		)
Other expense	2			—			—			—			2
Loss from investment in subsidiaries	131,282			—			6,443			(137,725		)	—
Total other (income) expenses	146,372			(259		)	6,443			(137,725		)	14,831
Loss before taxes	(189,858		)	(121,962		)	(12,886		)	137,725			(186,981		)
Provision (benefit) for income taxes:
Current	(1,074		)	—			—			—			(1,074		)
Deferred	—			2,877			—			—			2,877
Total income taxes	(1,074		)	2,877			—			—			1,803
Net loss	$	(188,784	)	$	(124,839	)	$	(12,886	)	$	137,725		$	(188,784	)
Comprehensive loss	$	(187,995	)	$	(124,839	)	$	(12,886	)	$	137,725		$	(187,995	)

17

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2015

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	4,350		$	103,157		$	—		$	—		$	107,507
Natural gas production	16,617			11,720			—			—			28,337
Natural gas liquids production	9,879			2,487			—			—			12,366
Other operational income	2,160			—			—			—			2,160
Derivative income, net	—			3,128			—			—			3,128
Total operating revenue	33,006			120,492			—			—			153,498
Operating expenses:
Lease operating expenses	4,976			22,601			—			—			27,577
Transportation, processing and gathering expenses	16,108			1,595			—			—			17,703
Production taxes	2,198			317			—			—			2,515
Depreciation, depletion and amortization	42,112			44,310			—			—			86,422
Write-down of oil and gas properties	491,412			—			—			—			491,412
Accretion expense	91			6,318			—			—			6,409
Salaries, general and administrative expenses	17,001			1			5			—			17,007
Incentive compensation expense	1,563			—			—			—			1,563
Other operational expenses	84			—			—			—			84
Total operating expenses	575,545			75,142			5			—			650,692
Income (loss) from operations	(542,539		)	45,350			(5		)	—			(497,194		)
Other (income) expenses:
Interest expense	10,344			21			—			—			10,365
Interest income	(101		)	(16		)	(5		)	—			(122		)
Other income	(133		)	(10		)	—			—			(143		)
Income from investment in subsidiaries	(29,027		)	—			—			29,027			—
Total other (income) expenses	(18,917		)	(5		)	(5		)	29,027			10,100
Income (loss) before taxes	(523,622		)	45,355			—			(29,027		)	(507,294		)
Provision (benefit) for income taxes:
Deferred	(196,234		)	16,328			—			—			(179,906		)
Total income taxes	(196,234		)	16,328			—			—			(179,906		)
Net income (loss)	$	(327,388	)	$	29,027		$	—		$	(29,027	)	$	(327,388	)
Comprehensive income (loss)	$	(339,891	)	$	29,027		$	—		$	(29,027	)	$	(339,891	)

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2016

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net loss	$	(188,784	)	$	(124,839	)	$	(12,886	)	$	137,725		$	(188,784	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	8,594			52,964			—			—			61,558
Write-down of oil and gas properties	9,324			119,531			349			—			129,204
Accretion expense	58			9,925			—			—			9,983
Deferred income tax provision	—			2,877			—			—			2,877
Settlement of asset retirement obligations	—			(3,768		)	(899		)	—			(4,667		)
Non-cash stock compensation expense	2,312			—			—			—			2,312
Non-cash derivative expense	—			192			—			—			192
Non-cash interest expense	4,635			—			—			—			4,635
Other non-cash expense	—			—			6,081			—			6,081
Change in current income taxes	(1,074		)	—			—			—			(1,074		)
Non-cash loss from investment in subsidiaries	131,282			—			6,443			(137,725		)	—
Change in intercompany receivables/payables	(1,657		)	1,657			—			—			—
(Increase) decrease in accounts receivable	(36,703		)	43,432			(884		)	—			5,845
(Increase) decrease in other current assets	(218		)	—			33			—			(185		)
Increase (decrease) in accounts payable	45			(2,183		)	—			—			(2,138		)
Increase in other current liabilities	3,813			85			—			—			3,898
Other	(39		)	(259		)	—			—			(298		)
Net cash (used in) provided by operating activities	(68,412		)	99,614			(1,763		)	—			29,439
Cash flows from investing activities:
Investment in oil and gas properties	(29,895		)	(99,615		)	(349		)	—			(129,859		)
Investment in fixed and other assets	(496		)	—			—			—			(496		)
Change in restricted funds	—			—			1,045			—			1,045
Investment in subsidiaries	—			—			718			(718		)	—
Net cash (used in) provided by investing activities	(30,391		)	(99,615		)	1,414			(718		)	(129,310		)
Cash flows from financing activities:
Proceeds from bank borrowings	477,000			—			—			—			477,000
Repayments of bank borrowings	(20,000		)	—			—			—			(20,000		)
Repayments of building loan	(95		)	—			—			—			(95		)
Equity proceeds from parent	—			—			(718		)	718			—
Net payments for share-based compensation	(650		)	—			—			—			(650		)
Net cash provided by (used in) financing activities	456,255			—			(718		)	718			456,255
Effect of exchange rate changes on cash	—			—			(9		)	—			(9		)
Net change in cash and cash equivalents	357,452			(1		)	(1,076		)	—			356,375
Cash and cash equivalents, beginning of period	9,681			2			1,076			—			10,759
Cash and cash equivalents, end of period	$	367,133		$	1		$	—		$	—		$	367,134

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

THREE MONTHS ENDED MARCH 31, 2015

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(327,388	)	$	29,027		$	—		$	(29,027	)	$	(327,388	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	42,112			44,310			—			—			86,422
Write-down of oil and gas properties	491,412			—			—			—			491,412
Accretion expense	91			6,318			—			—			6,409
Deferred income tax (benefit) provision	(196,234		)	16,328			—			—			(179,906		)
Settlement of asset retirement obligations	(1		)	(17,144		)	—			—			(17,145		)
Non-cash stock compensation expense	2,640			—			—			—			2,640
Non-cash derivative expense	—			1,511			—			—			1,511
Non-cash interest expense	4,318			—			—			—			4,318
Change in current income taxes	7,188			—			—			—			7,188
Non-cash income from investment in subsidiaries	(29,027		)	—			—			29,027			—
Change in intercompany receivables/payables	(33,748		)	25,548			8,200			—			—
Decrease in accounts receivable	3,606			4,600			—			—			8,206
Decrease in other current assets	1,881			—			2			—			1,883
(Increase) decrease in inventory	(2,415		)	2,415			—			—			—
Decrease in accounts payable	(1,007		)	(7,650		)	—			—			(8,657		)
Increase in other current liabilities	6,347			542			—			—			6,889
Other	(249		)	(11		)	—			—			(260		)
Net cash (used in) provided by operating activities	(30,474		)	105,794			8,202			—			83,522
Cash flows from investing activities:
Investment in oil and gas properties	(84,470		)	(77,229		)	(8,196		)	—			(169,895		)
Investment in fixed and other assets	(662		)	—			—			—			(662		)
Change in restricted funds	177,647			—			(5		)	—			177,642
Investment in subsidiaries	—			—			(8,168		)	8,168			—
Net cash provided by (used in) investing activities	92,515			(77,229		)	(16,369		)	8,168			7,085
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	—			—			8,168			(8,168		)	—
Net payments for share-based compensation	(2,991		)	—			—			—			(2,991		)
Net cash (used in) provided by financing activities	(2,991		)	—			8,168			(8,168		)	(2,991		)
Effect of exchange rate changes on cash	—			—			24			—			24
Net change in cash and cash equivalents	59,050			28,565			25			—			87,640
Cash and cash equivalents, beginning of period	72,886			1,450			152			—			74,488
Cash and cash equivalents, end of period	$	131,936		$	30,015		$	177		$	—		$	162,128

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this “Form 10-Q”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements as described in our 2015 Annual Report on Form 10-K and in this Form 10-Q.

Forward-looking statements may appear in a number of places in this Form 10-Q and include statements with respect to, among other things:

• any expected results or benefits associated with our acquisitions;

• expected results from risk-weighted drilling success;

• estimates of our future oil and natural gas production, including estimates of any increases in oil and natural gas production;

• planned capital expenditures and the availability of capital resources to fund capital expenditures;

• our outlook on oil and natural gas prices;

• estimates of our oil and natural gas reserves;

• any estimates of future earnings growth;

• the impact of political and regulatory developments;

• our outlook on the resolution of pending litigation and government inquiry;

• estimates of the impact of new accounting pronouncements on earnings in future periods;

• our future financial condition or results of operations and our future revenues and expenses;

• the outcome of restructuring efforts and asset sales;

• the amount, nature and timing of any potential acquisition or divestiture transactions;

• our access to capital and our anticipated liquidity;

• estimates of future income taxes; and

• our business strategy and other plans and objectives for future operations.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, among other things:

• commodity price volatility, including further or sustained declines in the prices we receive for our oil and natural gas production;

• consequences of a catastrophic event like the Deepwater Horizon oil spill;

• domestic and worldwide economic conditions, which may adversely affect the demand for and supply of oil and natural gas;

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

• our future level of indebtedness, liquidity, compliance with debt covenants and our ability to continue as a going concern;

• our future financial condition, results of operations, revenues, cash flows and expenses;

• the potential need to sell certain assets, restructure our debt, raise additional capital or seek bankruptcy protection;

• our ability to continue to borrow under our credit facility;

• our ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by BOEM;

• declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our bank credit facility and impairments;

• our ability to develop, explore for, acquire and replace oil and natural gas reserves and and sustain production;

• the impact of a financial crisis on our business operations, financial condition and ability to raise capital;

• the ability of financial counterparties to perform or fulfill their obligations under existing agreements;

• third-party interruption of sales to market;

• inflation;

• lack of availability and cost of goods and services;

• market conditions relating to potential acquisition and divestiture transactions;

• regulatory and environmental risks associated with drilling and production activities, including, for example, compliance with the Bureau of Safety and Environmental Enforcement's recently finalized well control rule;

• our ability to establish operations or production on our acreage prior to the expiration of related leaseholds;

• availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;

• competition in the oil and gas industry;

• our inability to retain and attract key personnel;

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• drilling and other operating risks;

• unsuccessful exploration and development drilling activities;

• hurricanes and other weather conditions;

• availability, cost and adequacy of insurance coverage;

• adverse effects of changes in applicable tax, environmental, derivatives, permitting, bonding and other regulatory requirements and legislation, as well as agency interpretation and enforcement and judicial decisions regarding the foregoing, including changes affecting our offshore and Appalachian operations;

• uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and

• other risks described in this Form 10-Q.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, Item 1A. Risk Factors, of this Form 10-Q and (2) Part I, Item 1A, of our 2015 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2015 Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in this Form 10-Q should be read in conjunction with the MD&A contained in our 2015 Annual Report on Form 10-K. 

Critical Accounting Estimates

Our 2015 Annual Report on Form 10-K describes the accounting estimates that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments. Our most significant estimates are:

• remaining proved oil and natural gas reserve volumes and the timing of their production;

• estimated costs to develop and produce proved oil and natural gas reserves;

• accruals of exploration costs, development costs, operating costs and production revenue;

• timing and future costs to abandon our oil and gas properties;

• effectiveness and estimated fair value of derivative positions;

• classification of unevaluated property costs;

• capitalized general and administrative costs and interest;

• estimates of fair value in business combinations;

• current and deferred income taxes; and

• contingencies.

This Form 10-Q should be read together with the discussion contained in our 2015 Annual Report on Form 10-K regarding these critical accounting policies.

Other Factors Affecting Our Business and Financial Results

In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our 2015 Annual Report on Form 10-K and in this Form 10-Q under Part II, Item 1A. Risk Factors, regarding our known material risk factors.

Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia.

We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016 and shut in our Mary field in Appalachia in September 2015. The lower commodity prices have negatively impacted our liquidity position. Additionally, the level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of May 4, 2016, we had total indebtedness of $1,544 million, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes, $457 million outstanding under our bank credit facility and $12 million outstanding under our Building Loan. As of March 31, 2016, we were in compliance with all of our financial covenants under our bank credit facility and the indentures governing our outstanding notes.However, given the lower

22

commodity prices and our reduced hedged position in 2016, we anticipate that we will exceed the Consolidated Funded Debt to consolidated EBITDA financial covenant of 3.75 to 1 set forth in our bank credit agreement at the end of the second quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. Additionally, on April 13, 2016, the borrowing base under our bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of certain actions, described in more detail below under "Liquidity and Capital Resources". The $175.3 million borrowing base deficiency is classified as a current liability at March 31, 2016.

In March 2016, we retained Lazard as our financial advisor and Latham & Watkins LLP as our legal advisor to assist the company in analyzing and considering financial, transactional and strategic alternatives. We also retained Alvarez & Marsal to assist the Company through this process. Additionally, in April 2016, the independent directors of our board of directors named current board member David T. Lawrence as a Special Liaison of the Independent Directors to work together with the management team of the company to help with assessing strategic and restructuring alternatives. Andrews Kurth LLP has also been hired as special counsel to the independent directors.

We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, asset sales and a prepackaged or prearranged bankruptcy filing. We are currently engaged in negotiations with financial advisors for the noteholders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes, and have an interest payment obligation under our 2022 Notes of approximately $29 million, due on May 16, 2016. We are also in discussions with our banks regarding an amendment to our bank credit facility. See "Liquidity and Capital Resources". Additionally, as part of this restructuring process, we are in discussions with certain vendors with whom we have significant contractual obligations. We cannot provide any assurances that we will be able to complete a private restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness.

Known Trends and Uncertainties

Declining Commodity Prices – We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016. Additionally, the low commodity prices have adversely affected the estimated value and quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties. For the years ended December 31, 2014 and 2015 and the first quarter of 2016, we recognized ceiling test write-downs of our oil and gas properties of $351 million, $1,362 million and $129 million, respectively. If NYMEX commodity prices remain at current levels (approximately $45 per Bbl of oil and $1.88 per MMBtu of natural gas), we would expect only minimal downward revisions of our estimated proved reserve quantities and would expect to recognize an additional ceiling test write-down between $75 and $175 million in the second quarter of 2016.

Bank Credit Facility– We were in compliance with all of our financial covenants under our bank credit facility and the indentures governing our outstanding notes as of March 31, 2016. However, given the lower commodity prices and our reduced hedged position in 2016, we anticipate that we will exceed the Consolidated Funded Debt to consolidated EBITDA financial covenant of 3.75 to 1 set forth in our bank credit facility at the end of the second quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.

Additionally, the significant decline in commodity prices has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. On April 13, 2016, the borrowing base under our bank credit facility was reduced from $500 million to $300 million, resulting in a $175.3 million borrowing base deficiency. See "Liquidity and Capital Resources". Continued low commodity prices or further declines in commodity prices could have a further adverse impact on the estimated value and quantities of our proved reserves and could result in additional reductions of our borrowing base under our bank credit facility.

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

23

the operator is no more than 50% of the operator's net worth.  Under the Draft Guidance, this waiver option would be eliminated and operators would only be able to self-insure for an amount that is no more than 10% of their tangible net worth.

On March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s current guidance to lessees. BOEM's notice letters indicate the amount of Stone's supplemental bonding needs could be as much as $565 million. However, we are in discussions with BOEM to reduce the amount of the supplemental bonding or other forms of financial assurance that the agency may require and the timing of when such bonds or financial assurances may need to be provided. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which remains subject to approval by BOEM. Currently, we have an aggregate of approximately $223 million posted in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. Our proposed tailored plan provides for posting some incremental financial assurances, and discussions on the approval and implementation of this plan are continuing with BOEM. We cannot provide assurance that our proposed plan will be acceptable to BOEM. Moreover, BOEM’s Draft Guidance is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which will in turn force these operators to seek additional surety bonds and could, consequently, exceed the surety bond market’s current capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety may have about the priority of their lien on the operator's collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

In addition, although the surety companies have not historically required collateral from us to back our surety bonds, some cash collateral will be required on a portion of our existing surety bonds as well as additional surety bonds we expect will be required to satisfy BOEM's financial assurance requirements. We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds to comply with supplemental bonding requirements of the BOEM. This need to obtain additional surety bonds, or some other form of financial assurances, could impact our liquidity. 

Hurricanes – Since a large portion of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable and practical insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time so we have eliminated our hurricane insurance coverage. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible increases to and/or acceleration of plugging and abandonment costs.

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.

Liquidity and Capital Resources

Overview.

On April 13, 2016, our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of certain actions, described in more detail below under "Bank Credit Facility". Additionally, we have $300 million of 2017 Convertible Notes that we need to restructure or repay by March 1, 2017, and we have an interest payment obligation under our 2022 Notes of approximately $29 million, due on May 16, 2016 (see "Senior Notes" below). As of May 4, 2016, we had cash on hand of approximately $350 million.

Our capital expenditure budget for 2016 has been set by the board of directors at $200 million, which assumes success in farming out the ENSCO 8503 deep water drilling rig to other operators for five to six months and the reduction in our working interests to acceptable levels on potential exploration wells to be drilled, or if unsuccessful, stacking the rig. The farm out subsidies and rig stacking expenses would be charges to our statement of operations as "Other operational expenses" and could range between $40 and $50 million. In early February 2016, we successfully executed one rig farm out arrangement for the ENSCO 8503 with another operator. The farm out ended in mid-April of 2016. We are working towards an agreement on a second farm out arrangement that is expected to commence prior to May 15, and continue discussions with other potential farm out and farm in partners. To further reduce capital expenditures for 2016, we have elected to suspend the Pompano drilling program after the completion of the initial development well, which is expected to be completed in early May of 2016. Additionally, if we have not secured partners for the Lamprey, Derbio or Rampart exploration wells, operations of the ENSCO 8503 deep water drilling rig are expected to be suspended in the third quarter of 2016, following the completion of the second farm out. The 2016 capital expenditure budget excludes material acquisitions and capitalized salaries, general

24

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

Based on our current outlook of commodity prices and our estimated production for 2016, we expect to fund our 2016 capital expenditures primarily with cash on hand from borrowings under our bank credit facility and expected cash flows from operating activities, as well as possible financings or asset sales. If we fall out of compliance with the covenants set forth in our bank credit facility at the end of the second quarter of 2016 and are unable to reach an agreement with our banks, find acceptable alternative financing or complete asset sales, then we may need to adjust our capital expenditure budget. In order to address the March 2017 maturity of our 2017 Convertible Notes, we continue to analyze a variety of financing options, including a restructuring with current holders of the 2017 Convertible Notes (which may include exchanges of our 2017 Convertible Notes for new debt and/or equity securities), securing a secondary credit facility or second lien notes, utilizing the current credit facility, sale or joint venture of core or non-core assets, a sale and leaseback of owned infrastructure and issuance of debt or equity in the public or private markets. Such transactions, if any, will depend on prevailing market conditions, contractual restrictions and other factors, some of which may be outside of our control. Current market conditions may put limitations on our ability to issue new debt or equity securities in the public or private markets. The ability of oil and gas companies to access the equity and high yield debt markets has been significantly limited since the significant decline in commodity prices throughout 2015 and into 2016.

Historically, we have been able to obtain an exemption from supplemental bonding requirements on our offshore leases for abandonment obligations based on financial net worth, however, on March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s current guidance to lessees. BOEM's notice letters indicate the amount of Stone's supplemental bonding needs could be as much as $565 million. We are in discussions with BOEM to reduce the amount of the supplemental bonding or other forms of financial assurance that the agency may require and the timing of when such bonds or financial assurances may need to be provided. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which remains subject to approval by BOEM. We currently have approximately $223 million posted in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations.Our proposed tailored plan provides for posting some incremental financial assurances, and discussions on the approval and implementation of this plan are ongoing. Although the surety companies have not historically required collateral from us to back our surety bonds, some cash collateral will be required on a portion of our existing surety bonds as well as additional surety bonds we expect will be required to satisfy BOEM's financial assurance requirements. This need to obtain additional surety bonds or some other form of financial assurance, could impact our liquidity. See Known Trends and Uncertainties.

Indebtedness.

Bank Credit Facility – On June 24, 2014, we entered into an amended and 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 and is guaranteed by our Guarantor Subsidiaries. The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. On April 13, 2016, we received notice that our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. We have not taken any action or made an election of actions to be taken to cure the borrowing base deficiency.

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

Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. 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

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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.

As of March 31, 2016, we were in compliance with all of our financial covenants under our bank credit facility and the indentures governing our outstanding notes. However, given the lower commodity prices and our reduced hedged position in 2016, we anticipate that we will exceed the Consolidated Funded Debt to consolidated EBITDA financial covenant of 3.75 to 1 set forth in our bank credit facility at the end of the second quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. We are currently in discussions with our banks regarding an amendment to our bank credit facility. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility.  If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments. 

Senior Notes – Our senior notes consist of $300 million of 2017 Convertible Notes and $775 million of 2022 Notes. The 2017 Convertible Notes will be due on March 1, 2017, unless earlier converted or repurchased by us at the option of the holder(s). We are actively analyzing a variety of financing options to address the March 2017 maturity of our 2017 Convertible Notes. We have an interest payment obligation under our 2022 Notes of approximately $29 million, due on May 16, 2016.The indenture governing the 2022 Notes provides a 30-day grace period that extends the latest date for making this cash interest payment to June 14, 2016 before an Event of Default occurs under the indenture, which would give the trustee or the holders of at least 25% in principal amount of the 2022 Notes the option to accelerate payment of the principal plus accrued and unpaid interest on the 2022 Notes. Although we have sufficient liquidity to make the interest payment by the due date, we may, alternatively, utilize the 30-day grace period provided for by the indenture, to allow us additional time to assess our restructuring alternatives.

Cash Flow and Working Capital.

Net cash provided by operating activities totaled $29.4 million during the three months ended March 31, 2016 compared to $83.5 million during the comparable period in 2015. The decrease was primarily due to the decline in our hedge-effected oil, natural gas and NGL prices and the decline in natural gas and NGL production volumes, partially offset by a decline in lease operating, transportation, processing and gathering and SG&A expenses. See "Results of Operations" for additional information relative to commodity prices, production and operating expense variances.

Net cash used in investing activities totaled $129.3 million during the three months ended March 31, 2016, which primarily represents our investment in oil and gas properties. Net cash provided by investing activities totaled $7.1 million during the three months ended March 31, 2015, which primarily represents our investment in oil and gas properties of $169.9 million, offset by $177.6 million of previously restricted proceeds from the sale of oil and gas properties.

Net cash provided by financing activities totaled $456.3 million during the three months ended March 31, 2016, which primarily represents $477.0 million of borrowings under our bank credit facility less $20.0 million in repayments of borrowings under our bank credit facility. Net cash used in financing activities totaled $3.0 million during the three months ended March 31, 2015, which primarily represents net payments for share-based compensation. During the three months ended March 31, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility.

We had a working capital deficit at March 31, 2016 of $87.5 million.

Capital Expenditures.

During the three months ended March 31, 2016, additions to oil and gas property costs of $87.3 million included $0.6 million of lease and property acquisition costs, $5.8 million of capitalized SG&A expenses (inclusive of incentive compensation) and $7.4 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities.

Contractual Obligations and Other Commitments

We have various contractual obligations and other commitments in the normal course of operations. For further information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Other Commitments” in our 2015 Annual Report on Form 10-K. There have been no material changes to this disclosure during the three months ended March 31, 2016.

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Results of Operations

The following table sets forth certain information with respect to our oil and gas operations:

	Three Months Ended March 31,
	2016		2015		Variance			% Change
Production:
Oil (MBbls)	1,635		1,622		13			1	%
Natural gas (MMcf)	6,846		11,157		(4,311		)	(39	)%
NGLs (MBbls)	364		683		(319		)	(47	)%
Oil, natural gas and NGLs (MBoe)	3,140		4,165		(1,025		)	(25	)%
Oil, natural gas and NGLs (MMcfe)	18,840		24,987		(6,147		)	(25	)%
Revenue data (in thousands): (1)
Oil revenue	$	60,275	$	107,507	$	(47,232	)	(44	)%
Natural gas revenue	15,173		28,337		(13,164		)	(46	)%
NGLs revenue	4,735		12,366		(7,631		)	(62	)%
Total oil, natural gas and NGL revenue	$	80,183	$	148,210	$	(68,027	)	(46	)%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	31.22	$	45.31	$	(14.09	)	(31	)%
Natural gas (per Mcf)	1.70		2.29		(0.59		)	(26	)%
NGLs (per Bbl)	13.01		18.11		(5.10		)	(28	)%
Oil, natural gas and NGLs (per Boe)	21.47		26.76		(5.29		)	(20	)%
Oil, natural gas and NGLs (per Mcfe)	3.58		4.46		(0.88		)	(20	)%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	36.87	$	66.28	$	(29.41	)	(44	)%
Natural gas (per Mcf)	2.22		2.54		(0.32		)	(13	)%
NGLs (per Bbl)	13.01		18.11		(5.10		)	(28	)%
Oil, natural gas and NGLs (per Boe)	25.54		35.58		(10.04		)	(28	)%
Oil, natural gas and NGLs (per Mcfe)	4.26		5.93		(1.67		)	(28	)%
Expenses (per Mcfe):
Lease operating expenses	$	1.04	$	1.10	$	(0.06	)	(5	)%
Transportation, processing and gathering expenses	0.04		0.71		(0.67		)	(94	)%
SG&A expenses (2)	0.73		0.68		0.05			7	%
DD&A expense on oil and gas properties	3.21		3.41		(0.20		)	(6	)%

(1) Includes the cash settlement of effective hedging contracts.

(2) Excludes incentive compensation expense.

Net Loss. During the three months ended March 31, 2016, we reported a net loss totaling approximately $188.8 million, or $3.39 per share, compared to a net loss for the three months ended March 31, 2015 of $327.4 million, or $5.93 per share. All per share amounts are on a diluted basis.

We follow the full cost method of accounting for oil and gas properties. During the three months ended March 31, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $128.9 million and $491.4 million, respectively. During the three months ended March 31, 2016, we recognized a ceiling test write-down of our Canadian oil and gas properties, which were deemed fully impaired at the end of 2015, totaling $0.3 million. The write-downs did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity.

The variance in the three month periods’ results was also due to the following components:

Production. During the three months ended March 31, 2016, total production volumes decreased to 18.8 Bcfe compared to 25.0 Bcfe produced during the comparable 2015 period, representing a 25% decrease. Oil production during the three months ended March 31, 2016 totaled approximately 1,635 MBbls compared to 1,622 MBbls produced during the comparable 2015 period. Natural gas production totaled 6.8 Bcf during the three months ended March 31, 2016 compared to 11.2 Bcf during the comparable 2015 period. NGL production during the three months ended March 31, 2016 totaled approximately 364 MBbls compared to 683 MBbls produced during the comparable

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2015 period. The decreases in natural gas and NGL production volumes were primarily attributable to the shut-in of production at our Mary field since September 2015.

Prices. Prices realized during the three months ended March 31, 2016 averaged $36.87 per Bbl of oil, $2.22 per Mcf of natural gas and $13.01 per Bbl of NGLs, or 28% lower, on an Mcfe basis, than average realized prices of $66.28 per Bbl of oil, $2.54 per Mcf of natural gas and $18.11 per Bbl of NGLs during the comparable 2015 period. All unit pricing amounts include the cash settlement of effective hedging contracts.

We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. Our effective hedging transactions increased our average realized natural gas price by $0.52 per Mcf and increased our average realized oil price by $5.65 per Bbl during the three months ended March 31, 2016. During the three months ended March 31, 2015, our effective hedging transactions increased our average realized natural gas price by $0.25 per Mcf and increased our average realized oil price by $20.97 per Bbl.

Revenue. Oil, natural gas and NGL revenue was $80.2 million during the three months ended March 31, 2016 compared to $148.2 million during the comparable period of 2015. The decrease in total revenue for the three months ended March 31, 2016 was primarily due to a 28% decrease in average realized prices and a 25% decrease in production volumes from the comparable period of 2015.

Derivative Income. Net derivative income for the three months ended March 31, 2016 totaled $0.1 million, comprised of $0.3 million of income from cash settlements and $0.2 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the three months ended March 31, 2015, net derivative income totaled $3.1 million, comprised of $4.6 million of income from cash settlements and $1.5 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.

Expenses. Lease operating expenses during the three months ended March 31, 2016 and 2015 totaled $19.5 million and $27.6 million, respectively. On a unit of production basis, lease operating expenses were $1.04 per Mcfe and $1.10 per Mcfe for the three months ended March 31, 2016 and 2015, respectively. The decrease in lease operating expenses during the three months ended March 31, 2016 was primarily attributable to service cost reductions, operating efficiencies and the shut-in of production at our Mary field since September 2015.

Transportation, processing and gathering expenses during the three months ended March 31, 2016 and 2015 totaled $0.8 million and $17.7 million, respectively, or $0.04 per Mcfe and $0.71 per Mcfe, respectively. The decrease was attributable to the shut-in of production at our Mary field since September 2015 as well as the recoupment of previously paid transportation costs allocable to the Federal government's portion of certain of our deep water production, which amounted to approximately $4 million.

Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the three months ended March 31, 2016 totaled $60.4 million compared to $85.2 million during the comparable period of 2015. On a unit of production basis, DD&A expense was $3.21 per Mcfe and $3.41 per Mcfe during the three months ended March 31, 2016 and 2015, respectively. The decrease in DD&A during the three months ended March 31, 2016 was primarily due to the ceiling test write-downs of our oil and gas properties.

Other operational expenses for the three months ended March 31, 2016 and 2015 totaled $12.5 million and $0.1 million, respectively. Included in other operational expenses for the three months ended March 31, 2016 is a $6.0 million loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments which were reclassified from accumulated other comprehensive income. Also included in other operational expenses for the three months ended March 31, 2016 are approximately $6.1 million of rig subsidy charges related to the farm out of the ENSCO 8503 deep water drilling rig and stacking charges related to the Saxon Appalachian rig.

SG&A expenses (exclusive of incentive compensation) for the three months ended March 31, 2016 were $13.7 million compared to $17.0 million for the three months ended March 31, 2015. On a unit of production basis, SG&A expenses were $0.73 per Mcfe and $0.68 per Mcfe for the three months ended March 31, 2016 and 2015, respectively. The decrease in SG&A expenses for the three months ended March 31, 2016 related primarily to a reduction of our workforce. SG&A expenses for the three months ended March 31, 2016 included approximately $1 million of professional fees associated with our debt restructuring efforts.

For the three months ended March 31, 2016 and 2015, incentive compensation expense totaled $5.0 million and $1.6 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 March 31, 2016 totaled $15.2 million, net of $7.4 million of capitalized interest, compared to interest expense of $10.4 million, net of $10.8 million of capitalized interest, during the comparable 2015 period. The increase in interest expense was primarily the result of a decrease in the amount of interest capitalized to oil and gas properties and interest expense associated with the increased borrowings under our bank credit facility.

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For the three months ended March 31, 2016 and 2015, we recorded an income tax provision (benefit) of $1.8 million and ($179.9) million, respectively. The income tax benefit recorded for the three months ended March 31, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs of our oil and gas properties. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined in the third quarter of 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. The change in the valuation allowance was recorded as an adjustment to income tax expense.

Off-Balance Sheet Arrangements

None.

Recent Accounting Developments

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. We are currently evaluating the effect that this new standard may have on our financial statements.

In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.

Defined Terms

Oil, condensate and NGLs are stated in barrels (“Bbls”) or thousand barrels (“MBbls”). Natural gas is stated in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). Oil, condensate and NGLs are converted to natural gas at a ratio of one barrel of liquids per six Mcf of gas. Bcfe, MMcfe and Mcfe represent one billion cubic feet, one million cubic feet and one thousand cubic feet of gas equivalent, respectively. MMBoe and MBoe represent one million and one thousand barrels of oil equivalent, respectively. MMBtu represents one million British Thermal Units. An active property is an oil and gas property with existing production. A primary term lease is an oil and gas property with no existing production, in which we have a specific time frame to establish production without losing the rights to explore the property. Liquidity is defined as the ability to obtain cash quickly either through the conversion of assets or incurrence of liabilities.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. For the three months ended March 31, 2016, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $4.8 million impact on our revenues. Excluding the effects of hedging contracts, a 10% fluctuation in realized oil and natural gas prices would have had an approximate $6.7 million impact on our revenues. In order to manage our exposure to oil and natural gas price declines, we enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.

Our hedging policy currently provides that not more than 60% of our estimated production quantities can be hedged for any given year without the consent of the board of directors. We believe that our hedging positions as of May 4, 2016 have hedged approximately 28% of our estimated 2016 production from estimated proved reserves. Although we continue to monitor the marketplace for additional hedges for 2016 and beyond, continued weakness in commodity prices may impair our ability to secure hedges at prices we deem acceptable. See Part I, Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities, of this Form 10-Q for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Since the filing of our 2015 Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to commodity prices.

Interest Rate Risk

We had total debt outstanding of $1,544 million at March 31, 2016, of which $1,087 million, or 70%, bears interest at fixed rates. The $1,087 million of fixed-rate debt is comprised of $300 million of the 2017 Convertible Notes, $775 million of the 2022 Notes and $12 million of the Building Loan. At March 31, 2016, the remaining $457 million of our outstanding debt bears interest at an adjustable interest rate and consists of borrowings outstanding under our bank credit facility. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources of this Form 10-Q. Borrowings under our bank credit facility may subject us to increased sensitivity to interest rate movements. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. At March 31, 2016, the weighted average interest rate under our bank credit facility was approximately 3.5% per annum.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2016 at the reasonable assurance level.

Changes in Internal Controls Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended March 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees.

In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. On November 12, 2015, the Plaquemines Parish Council passed a resolution instructing its attorneys to dismiss all 21 Coastal Zone Management suits filed by the Plaquemines Parish. To date, counsel for the Plaquemines Parish has not yet moved to dismiss the cases. On January 12, 2016, Stone moved to dismiss the action without prejudice. Plaintiff has not yet opposed the motion.

On October 10, 2012, Stone received notice from the Bureau of Safety and Environmental Enforcement (“BSEE”) that it was initiating an enforcement proceeding with respect to an Incident of Non-Compliance observed at Stone's Vermillion Block 255 H Platform on April 19, 2012. Stone does not agree that the conditions observed were violations of applicable rules. BSEE issued a Reviewing Officer’s Final Decision dated July 9, 2013, assessing a penalty against Stone of $200,000, which was calculated as $25,000 per day for eight days of alleged improper venting of gas at the platform. On August 12, 2015, the Interior Board of Land Appeals affirmed the penalty. Stone's subsequent appeal to the Director of the Department of the Interior Office of Hearings and Appeals was unsuccessful. Stone paid the $200,000 penalty on March 28, 2016 and the matter is now closed.

On November 17, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. Prior to this, in September 2014, Stone had transferred ownership of the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. Reclamation of the site by Southwestern, with the participation of the PADEP and Stone, is now complete. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.

Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters.

Item 1A. Risk Factors

The following updates the Risk Factors included in our 2015 Annual Report on Form 10-K. Except as set forth below, there have been no material changes with respect to Stone’s risk factors previously reported in Part I, Item 1A, of our 2015 Annual Report on Form 10-K.

The closing market price of our common stock has recently declined significantly. On April 29, 2016, we were notified by the New York Stock Exchange (the “NYSE”) that our common stock was not in compliance with NYSE listing standards. If we are unable to cure the stock price deficiency, our common stock could be delisted from the New York Stock Exchange (the “NYSE”) or trading could be suspended.

Our common stock is currently listed on the NYSE. In order for our common stock to continue to be listed on the NYSE, we are required to comply with various listing standards, including the maintenance of a minimum average closing price of at least $1.00 per share during a consecutive 30 trading-day period. In addition to the minimum average closing price criteria, we are considered to be below compliance if our average market capitalization over a consecutive 30 day-trading period is less than $50 million and, at the same time, our stockholders’ equity is less than $50 million.

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On April 29, 2016, we were notified by the NYSE that the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days. Under the NYSE’s rules, we have six months following receipt of the notification to regain compliance with the minimum share price requirement or the average market capitalization and stockholders’ equity requirements. Although we have an opportunity to take action to cure such a breach, if we do not succeed, the NYSE could commence suspension or delisting procedures in respect of our common stock. In addition, our common stock could be delisted pursuant to Section 802.01 of the NYSE Listed Company Manual if the trading price of our common stock on the NYSE is abnormally low, which has generally been interpreted to mean at levels below $0.16 per share, and our common stock could also be delisted pursuant to Section 802.01 if our average market capitalization over a consecutive 30 day-trading period is less than $15 million. In these events, we would not have an opportunity to cure the stock price deficiency or market capitalization deficiency, and our shares would be delisted immediately and suspended from trading on the NYSE. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise additional necessary capital through equity or debt financing, and attract and retain personnel by means of equity compensation, would be greatly impaired. Furthermore, with respect to any suspended or delisted securities, we would expect decreases in institutional and other investor demand, analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such securities. A suspension or delisting would likely decrease the attractiveness of our common stock to investors and cause the trading volume of our common stock to decline, which could result in a further decline in the market price of our common stock.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the three months ended March 31, 2016: 

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	Approximate Dollar Value of Shares that MayYet be Purchased Under the Plans or Programs
January 1 - January 31, 2016	237,454	$	2.74	—
February 1 - February 29, 2016	—	—		—
March 1 - March 31, 2016	—	—		—
	237,454	$	2.74	—	$	92,928,632

(1) Amount includes shares of our common stock withheld from employees and nonemployee directors upon the vesting of restricted stock in order to satisfy the required tax withholding obligations.

(2) There were no repurchases of our common stock under our share repurchase program during the three months ended March 31, 2016.

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Item 6. Exhibits

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

______________________________________________

* Filed or furnished herewith.

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		STONE ENERGY CORPORATION
Date:	May 5, 2016	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)).
*10.1	Stone Energy Corporation 2016 Performance Incentive Compensation Plan (approved March 10, 2016).
*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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