Document



	June 30, 2016			December 31, 2015
	(Unaudited)			(Note 1)
Assets
Current assets:
Cash and cash equivalents	$	169,194		$	10,759
Accounts receivable	38,276			48,031
Fair value of derivative contracts	11,887			38,576
Current income tax receivable	46,174			46,174
Other current assets	12,080			6,881
Total current assets	277,611			150,421
Oil and gas properties, full cost method of accounting:
Proved	9,518,245			9,375,898
Less: accumulated depreciation, depletion and amortization	(8,960,440		)	(8,603,955		)
Net proved oil and gas properties	557,805			771,943
Unevaluated	425,204			440,043
Other property and equipment, net	27,968			29,289
Other assets, net	28,183			18,473
Total assets	$	1,316,771		$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	28,914		$	82,207
Undistributed oil and gas proceeds	5,071			5,992
Accrued interest	9,773			9,022
Fair value of derivative contracts	37			—
Asset retirement obligations	33,695			21,291
Current portion of long-term debt	288,336			—
Other current liabilities	34,793			40,712
Total current liabilities	400,619			159,224
Long-term debt	1,122,901			1,060,955
Asset retirement obligations	203,661			204,575
Other long-term liabilities	18,446			25,204
Total liabilities	1,745,627			1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 30,000,000 shares; issued 5,592,641 and 5,530,232 shares, respectively	56			55
Treasury stock (1,658 shares, at cost)	(860		)	(860		)
Additional paid-in capital	1,654,731			1,648,687
Accumulated deficit	(2,090,168		)	(1,705,623		)
Accumulated other comprehensive income	7,385			17,952
Total stockholders’ equity	(428,856		)	(39,789		)
Total liabilities and stockholders’ equity	$	1,316,771		$	1,410,169



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Operating revenue:
Oil production	$	72,711		$	111,585		$	132,986		$	219,092
Natural gas production	12,553			26,907			27,726			55,244
Natural gas liquids production	3,718			11,033			8,453			23,399
Other operational income	337			—			693			1,792
Derivative income, net	—			—			—			2,427
Total operating revenue	89,319			149,525			169,858			301,954
Operating expenses:
Lease operating expenses	18,826			27,429			38,373			55,006
Transportation, processing and gathering expenses	7,183			19,940			8,024			37,643
Production taxes	578			1,827			1,059			4,342
Depreciation, depletion and amortization	46,231			77,951			107,789			164,373
Write-down of oil and gas properties	118,649			224,294			247,853			715,706
Accretion expense	10,082			6,408			20,065			12,817
Salaries, general and administrative expenses	20,014			16,418			32,768			33,425
Incentive compensation expense	4,670			1,264			9,649			2,827
Restructuring fees	9,436			—			10,389			—
Other operational expenses	27,680			1,454			40,207			1,170
Derivative expense, net	626			701			488			—
Total operating expenses	263,975			377,686			516,664			1,027,309
Loss from operations	(174,656		)	(228,161		)	(346,806		)	(725,355		)
Other (income) expenses:
Interest expense	17,599			10,472			32,840			20,837
Interest income	(302		)	(66		)	(416		)	(188		)
Other income	(270		)	(613		)	(568		)	(756		)
Other expense	9			—			11			—
Total other expenses	17,036			9,793			31,867			19,893
Loss before income taxes	(191,692		)	(237,954		)	(378,673		)	(745,248		)
Provision (benefit) for income taxes:
Current	(2,113		)	—			(3,187		)	—
Deferred	6,182			(85,048		)	9,059			(264,954		)
Total income taxes	4,069			(85,048		)	5,872			(264,954		)
Net loss	$	(195,761	)	$	(152,906	)	$	(384,545	)	$	(480,294	)
Basic loss per share	$	(35.05	)	$	(27.68	)	$	(68.94	)	$	(86.99	)
Diluted loss per share	$	(35.05	)	$	(27.68	)	$	(68.94	)	$	(86.99	)
Average shares outstanding	5,585			5,525			5,578			5,521
Average shares outstanding assuming dilution	5,585			5,525			5,578			5,521



	Six Months Ended June 30,
	2016			2015
Cash flows from operating activities:
Net loss	$	(384,545	)	$	(480,294	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	107,789			164,373
Write-down of oil and gas properties	247,853			715,706
Accretion expense	20,065			12,817
Deferred income tax provision (benefit)	9,059			(264,954		)
Settlement of asset retirement obligations	(10,706		)	(35,923		)
Non-cash stock compensation expense	4,682			6,028
Non-cash derivative expense	1,025			7,931
Non-cash interest expense	9,403			8,737
Other non-cash expense	6,081			—
Change in current income taxes	(3,187		)	7,206
Decrease in accounts receivable	9,755			23,047
Increase in other current assets	(5,283		)	(1,959		)
Decrease in accounts payable	(321		)	(7,826		)
Decrease in other current liabilities	(5,920		)	(8,720		)
Other	(7,880		)	(504		)
Net cash (used in) provided by operating activities	(2,130		)	145,665
Cash flows from investing activities:
Investment in oil and gas properties	(179,311		)	(264,355		)
Proceeds from sale of oil and gas properties, net of expenses	—			10,100
Investment in fixed and other assets	(898		)	(727		)
Change in restricted funds	1,045			179,475
Net cash used in investing activities	(179,164		)	(75,507		)
Cash flows from financing activities:
Proceeds from bank borrowings	477,000			5,000
Repayments of bank borrowings	(135,500		)	(5,000		)
Repayments of building loan	(189		)	—
Deferred financing costs	(900		)	—
Net payments for share-based compensation	(673		)	(3,069		)
Net cash provided by (used in) financing activities	339,738			(3,069		)
Effect of exchange rate changes on cash	(9		)	78
Net change in cash and cash equivalents	158,435			67,167
Cash and cash equivalents, beginning of period	10,759			74,488
Cash and cash equivalents, end of period	$	169,194		$	141,655

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

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

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 $1,428 million as of June 30, 2016 and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness, particularly the maximum Consolidated Funded Debt to consolidated EBITDA (“Consolidated Funded Leverage”) financial covenant set forth in our bank credit agreement. If we exceed the maximum Consolidated Funded Leverage financial covenant, we would be required to seek a waiver or amendment from our bank lenders. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it would result in an event of default and may result in the acceleration of our other debt instruments.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(In thousands, except per share data)
Income (numerator):
Basic:
Net loss	$	(195,761	)	$	(152,906	)	$	(384,545	)	$	(480,294	)
Net income attributable to participating securities	—			—			—			—
Net loss attributable to common stock - basic	$	(195,761	)	$	(152,906	)	$	(384,545	)	$	(480,294	)
Diluted:
Net loss	$	(195,761	)	$	(152,906	)	$	(384,545	)	$	(480,294	)
Net income attributable to participating securities	—			—			—			—
Net loss attributable to common stock - diluted	$	(195,761	)	$	(152,906	)	$	(384,545	)	$	(480,294	)
Weighted average shares (denominator):
Weighted average shares - basic	5,585			5,525			5,578			5,521
Dilutive effect of stock options	—			—			—			—
Dilutive effect of convertible notes	—			—			—			—
Weighted average shares - diluted	5,585			5,525			5,578			5,521
Basic loss per share	$	(35.05	)	$	(27.68	)	$	(68.94	)	$	(86.99	)
Diluted loss per share	$	(35.05	)	$	(27.68	)	$	(68.94	)	$	(86.99	)

For the three and six months ended June 30, 2016 and 2015, the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such periods. For the three and six months ended June 30, 2016 and 2015, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 5 – Debt) and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in Note 5 – Debt), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.

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.

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

We have entered into fixed-price swaps and 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 August 2, 2016, two counterparties accounted for approximately 86% of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility.

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 June 30, 2016, we had accumulated other comprehensive income of $7.4 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of June 30, 2016. The $7.4 million of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.



Fair Value of Derivatives Qualifying as Hedging Instruments at
June 30, 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	$	11.9	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	—		Long-term liabilities: Fair value of derivative contracts	—
		$	11.9		$	—

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		$	—



Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended June 30, 2016 and 2015
(In millions)
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives						Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)					Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2016			2015			Location	2016		2015		Location	2016			2015
Commodity contracts	$	(8.6	)	$	(18.8	)	Operating revenue - oil/natural gas production	$	8.9	$	30.4	Derivative income (expense), net	$	(0.6	)	$	(0.4	)
Total	$	(8.6	)	$	(18.8	)		$	8.9	$	30.4		$	(0.6	)	$	(0.4	)



Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Six Months Ended June 30, 2016 and 2015
(In millions)
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives					Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)					Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2016			2015		Location	2016		2015		Location	2016			2015
Commodity contracts	$	(4.0	)	$	4.1	Operating revenue - oil/natural gas production	$	21.7	$	67.2	Derivative income (expense), net	$	(0.5	)	$	0.5
Total	$	(4.0	)	$	4.1		$	21.7	$	67.2		$	(0.5	)	$	0.5

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 June 30, 2016, all of our derivative contracts, other than our collar contract, were in an asset position. The potential impact of the rights of offset of our collar contract was immaterial at June 30, 2016. As of December 31, 2015, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

Revolving Credit Facility. On June 24, 2014, we entered into a revolving credit facility (the Fourth Amended and Restated Credit Agreement dated as of June 24, 2014) with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, with an initial borrowing base of $500 million. The bank credit facility matures on July 1, 2019. 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, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. We elected to pay the

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

On June 30 and August 2, 2016, we had $341.5 million of outstanding borrowings and $18.3 million of outstanding letters of credit, leaving $0.2 million of availability under the bank credit facility. The weighted average interest rate under the bank credit facility was approximately 4.3% at June 30, 2016. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of June 30, 2016, the bank credit facility was guaranteed by Stone Energy Offshore, L.L.C. (“Stone Offshore”), SEO A LLC and SEO B LLC (collectively, the “Guarantor Subsidiaries”).

The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank credit facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. However, the Amendment provides for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties. The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage, and grant a security interest in, our oil and natural gas reserves representing at least 86% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Interest on loans under the bank credit facility is calculated using the London Interbank Offering (“LIBOR”) rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%.

In addition to the covenants discussed above, the bank credit facility provides that we must 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. The bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of June 30, 2016.

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

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 703,347 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes (after the effectiveness of the reverse stock split of 1-for-10), also subject to adjustment, and are exercisable upon conversion of the 2017 Convertible Notes.

We also entered into separate warrant transactions whereby, in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately 703,347 shares of our common stock (the “Sold Warrants”) at a strike price of $559.10 per share of our common stock (after the effectiveness of the reverse stock split of 1-for-10). We received aggregate proceeds of approximately $40.1 million from the sale of the Sold Warrants to the Dealers. If, upon expiration of the Sold Warrants, the price per share of our common stock, as measured under the Sold Warrants, is greater than the strike price of the Sold Warrants, we will be required to issue, without further consideration, under each Sold Warrant a number of shares of our common stock with a value equal to the amount of such difference.

As of June 30, 2016, the carrying amount of the liability component of the 2017 Convertible Notes of $287.9 million was classified as a current liability. During the three and six months ended June 30, 2016, we recognized $4.0 million and $7.9 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $0.8 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and six months ended June 30, 2015, we recognized $3.7 million and $7.4 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $0.7 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and six month periods ended June 30, 2016, we recognized $1.3 million and $2.6 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes. During the three and six month periods ended June 30, 2015, we recognized $1.3 million and $2.6 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

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 June 30, 2016, our valuation allowance totaled $322.8 million. Our effective tax rate for the six months ended June 30, 2016 was 2.1%. This percentage differed from the federal statutory rate of 35.0% primarily due to the establishment of the valuation allowance 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 June 30, 2016, which relates to expected tax refunds from the carryback of net operating losses to previous tax years. Additionally, we had $3.2 million of non-current income tax receivables at June 30, 2016 reflected in Other Assets, as they aren’t expected to be received within twelve months.

As of June 30, 2016 and December 31, 2015, we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call portion of the collar. For a more detailed description of our derivative instruments, see Note 4 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.



	Cash Flow Hedges			Foreign Currency Items		Total
Three Months Ended June 30, 2016
Beginning balance, net of tax	$	18.7		$	—	$	18.7
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	(8.6		)	—		(8.6		)
Income tax effect	3.1			—		3.1
Net of tax	(5.5		)	—		(5.5		)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	8.9			—		8.9
Income tax effect	(3.1		)	—		(3.1		)
Net of tax	5.8			—		5.8
Other comprehensive loss, net of tax	(11.3		)	—		(11.3		)
Ending balance, net of tax	$	7.4		$	—	$	7.4



	Cash Flow Hedges			Foreign Currency Items			Total
Six Months Ended June 30, 2016
Beginning balance, net of tax	$	24.0		$	(6.0	)	$	18.0
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	(4.0		)	—			(4.0		)
Income tax effect	1.4			—			1.4
Net of tax	(2.6		)	—			(2.6		)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	21.7			—			21.7
Other operational expenses	—			(6.0		)	(6.0		)
Income tax effect	(7.7		)	—			(7.7		)
Net of tax	14.0			(6.0		)	8.0
Other comprehensive income (loss), net of tax	(16.6		)	6.0			(10.6		)
Ending balance, net of tax	$	7.4		$	—		$	7.4



	Cash Flow Hedges			Foreign Currency Items			Total
Three Months Ended June 30, 2015
Beginning balance, net of tax	$	77.9		$	(7.1	)	$	70.8
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	(18.8		)	—			(18.8		)
Foreign currency translations	—			1.3			1.3
Income tax effect	6.9			—			6.9
Net of tax	(11.9		)	1.3			(10.6		)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	30.4			—			30.4
Income tax effect	(10.9		)	—			(10.9		)
Net of tax	19.5			—			19.5
Other comprehensive income (loss), net of tax	(31.4		)	1.3			(30.1		)
Ending balance, net of tax	$	46.5		$	(5.8	)	$	40.7



	Cash Flow Hedges			Foreign Currency Items			Total
Six Months Ended June 30, 2015
Beginning balance, net of tax	$	86.8		$	(3.5	)	$	83.3
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	4.1			—			4.1
Foreign currency translations	—			(2.3		)	(2.3		)
Income tax effect	(1.3		)	—			(1.3		)
Net of tax	2.8			(2.3		)	0.5
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	67.2			—			67.2
Income tax effect	(24.1		)	—			(24.1		)
Net of tax	43.1			—			43.1
Other comprehensive loss, net of tax	(40.3		)	(2.3		)	(42.6		)
Ending balance, net of tax	$	46.5		$	(5.8	)	$	40.7

Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows. At June 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $118.6 million based on twelve-month average prices, net of applicable differentials, of $43.49 per Bbl of oil, $1.93 per Mcf of natural gas and $9.33 per Bbl of natural gas liquids ("NGLs"). The write-down at June 30, 2016 was decreased by $18.1 million as a result of hedges. At March 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $128.9 million based on twelve-month average prices, net of applicable differentials, of $46.72 per Bbl of oil, $2.01 per Mcf of natural gas and $13.65 per Bbl of 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 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.

Included in other operational expenses for the six months ended June 30, 2016 is a $6.0 million loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See Note 9 – Accumulated Other Comprehensive Income (Loss). Also included in other operational expenses for the six months ended June 30, 2016 are approximately $13.6 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and the platform rig at Pompano and a $20 million charge related to the termination of our deep water drilling rig contract with Ensco.

In March 2016, we retained Lazard as our financial advisor and Latham & Watkins LLP as our legal advisor to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We also retained Alvarez & Marsal to assist the Company through this process. In April 2016, the independent directors of our board of directors named current board member David T. Lawrence a Special Liaison of the Independent Directors to work together with the management team of the Company to help with assessing strategic and restructuring alternatives. Andrews Kurth LLP has also been hired as special counsel to the independent directors. Additionally, we are engaged in negotiations with financial advisors for certain holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes and in June 2016, we secured an amendment to our existing credit facility with our bank group. The legal and financial advisory costs associated with these restructuring efforts are included in the statement of operations as restructuring fees and totaled $9.4 million and $10.4 million for the three and six months ended June 30, 2016, respectively.

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 guidance to lessees at such time. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as $565 million. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $230 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed plan would require approximately $16 million of incremental financial assurance or bonding for 2016, a majority of which may require cash collateral. Under the submitted plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Additionally, on July 14, 2016, BOEM issued a Notice to Lessees (“NTL”) that augments requirements for the posting of additional financial assurances by offshore lessees. We are reviewing the new NTL and its potential impact to Stone.

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.

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 Section 802.01C of the NYSE Listed Company Manual. On May 17, 2016, we were notified by the NYSE that our average global market capitalization had been less than $50 million over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50 million, which is non-compliant with Section 802.01B of the NYSE Listed Company Manual.

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

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 June 30, 2016 and December 31, 2015 and for the three and six month periods ended June 30, 2016 and 2015 on an issuer (parent company), Guarantor Subsidiaries, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	169,193		$	1		$	—		$	—		$	169,194
Accounts receivable	25,410			31,171			883			(19,188		)	38,276
Fair value of derivative contracts	—			11,887			—			—			11,887
Current income tax receivable	46,174			—			—			—			46,174
Other current assets	12,080			—			—			—			12,080
Total current assets	252,857			43,059			883			(19,188		)	277,611
Oil and gas properties, full cost method:
Proved	1,907,347			7,565,003			45,895			—			9,518,245
Less: accumulated DD&A	(1,907,326		)	(7,007,219		)	(45,895		)	—			(8,960,440		)
Net proved oil and gas properties	21			557,784			—			—			557,805
Unevaluated	261,971			163,233			—			—			425,204
Other property and equipment, net	27,968			—			—			—			27,968
Other assets, net	27,445			738			—			—			28,183
Investment in subsidiary	503,738			—			—			(503,738		)	—
Total assets	$	1,074,000		$	764,814		$	883		$	(522,926	)	$	1,316,771
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	23,153		$	24,950		$	—		$	(19,189	)	$	28,914
Undistributed oil and gas proceeds	4,379			692			—			—			5,071
Accrued interest	9,773			—			—			—			9,773
Fair value of derivative contracts	—			37			—			—			37
Asset retirement obligations	—			33,695			—			—			33,695
Current portion of long-term debt	288,336			—			—			—			288,336
Other current liabilities	34,513			280			—			—			34,793
Total current liabilities	360,154			59,654			—			(19,189		)	400,619
Long-term debt	1,122,901			—			—			—			1,122,901
Asset retirement obligations	1,355			202,306			—			—			203,661
Other long-term liabilities	18,446						—			—			18,446
Total liabilities	1,502,856			261,960			—			(19,189		)	1,745,627
Commitments and contingencies
Stockholders’ equity:
Common stock	56			—			—			—			56
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,654,731			1,344,577			109,078			(1,453,655		)	1,654,731
Accumulated deficit	(2,090,168		)	(849,108		)	(108,195		)	957,303			(2,090,168		)
Accumulated other comprehensive income	7,385			7,385			—			(7,385		)	7,385
Total stockholders’ equity	(428,856		)	502,854			883			(503,737		)	(428,856		)
Total liabilities and stockholders’ equity	$	1,074,000		$	764,814		$	883		$	(522,926	)	$	1,316,771



	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
Other current assets	6,848			—			33			—			6,881
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	55			—			—			—			55
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,648,687			1,344,577			109,795			(1,454,372		)	1,648,687
Accumulated deficit	(1,705,623		)	(624,824		)	(95,306		)	720,130			(1,705,623		)
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



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	1,323		$	71,388		$	—		$	—		$	72,711
Natural gas production	3,959			8,594			—			—			12,553
Natural gas liquids production	2,375			1,343			—			—			3,718
Other operational income	337			—			—			—			337
Total operating revenue	7,994			81,325			—			—			89,319
Operating expenses:
Lease operating expenses	3,814			15,012			—			—			18,826
Transportation, processing and gathering expenses	6,021			1,162			—			—			7,183
Production taxes	383			195			—			—			578
Depreciation, depletion and amortization	10,470			35,761			—			—			46,231
Write-down of oil and gas properties	6,534			112,114			1			—			118,649
Accretion expense	58			10,024			—			—			10,082
Salaries, general and administrative expenses	20,013			1			—			—			20,014
Incentive compensation expense	4,670			—			—			—			4,670
Restructuring fees	9,436			—			—			—			9,436
Other operational expenses	27,736			(57		)	1			—			27,680
Derivative expense, net	—			626			—			—			626
Total operating expenses	89,135			174,838			2			—			263,975
Loss from operations	(81,141		)	(93,513		)	(2		)	—			(174,656		)
Other (income) expenses:
Interest expense	17,599			—			—			—			17,599
Interest income	(302		)	—			—			—			(302		)
Other income	(20		)	(250		)	—			—			(270		)
Other expense	9			—			—			—			9
Loss from investment in subsidiaries	99,447			—			1			(99,448		)	—
Total other (income) expenses	116,733			(250		)	1			(99,448		)	17,036
Loss before taxes	(197,874		)	(93,263		)	(3		)	99,448			(191,692		)
Provision (benefit) for income taxes:
Current	(2,113		)	—			—			—			(2,113		)
Deferred	—			6,182			—			—			6,182
Total income taxes	(2,113		)	6,182			—			—			4,069
Net loss	$	(195,761	)	$	(99,445	)	$	(3	)	$	99,448		$	(195,761	)
Comprehensive loss	$	(207,117	)	$	(99,445	)	$	(3	)	$	99,448		$	(207,117	)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	6,504		$	105,081		$	—		$	—		$	111,585
Natural gas production	15,647			11,260			—			—			26,907
Natural gas liquids production	8,077			2,956			—			—			11,033
Total operating revenue	30,228			119,297			—			—			149,525
Operating expenses:
Lease operating expenses	5,111			22,318			—			—			27,429
Transportation, processing and gathering expenses	17,974			1,966			—			—			19,940
Production taxes	1,436			391			—			—			1,827
Depreciation, depletion and amortization	44,052			33,899			—			—			77,951
Write-down of oil and gas properties	179,125			—			45,169			—			224,294
Accretion expense	91			6,317			—			—			6,408
Salaries, general and administrative expenses	16,398			—			20			—			16,418
Incentive compensation expense	1,264			—			—			—			1,264
Other operational expenses	1,454			—			—			—			1,454
Derivative expense, net	—			701			—			—			701
Total operating expenses	266,905			65,592			45,189			—			377,686
Income (loss) from operations	(236,677		)	53,705			(45,189		)	—			(228,161		)
Other (income) expenses:
Interest expense	10,472			—			—			—			10,472
Interest income	(46		)	(19		)	(1		)	—			(66		)
Other income	(187		)	(423		)	(3		)	—			(613		)
(Income) loss from investment in subsidiaries	(16,147		)	—			28,918			(12,771		)	—
Total other (income) expenses	(5,908		)	(442		)	28,914			(12,771		)	9,793
Income (loss) before taxes	(230,769		)	54,147			(74,103		)	12,771			(237,954		)
Provision (benefit) for income taxes:
Deferred	(77,863		)	9,082			(16,267		)	—			(85,048		)
Total income taxes	(77,863		)	9,082			(16,267		)	—			(85,048		)
Net income (loss)	$	(152,906	)	$	45,065		$	(57,836	)	$	12,771		$	(152,906	)
Comprehensive income (loss)	$	(183,062	)	$	45,065		$	(57,836	)	$	12,771		$	(183,062	)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	1,384		$	131,602		$	—		$	—		$	132,986
Natural gas production	6,426			21,300			—			—			27,726
Natural gas liquids production	3,509			4,944			—			—			8,453
Other operational income	693			—			—			—			693
Total operating revenue	12,012			157,846			—			—			169,858
Operating expenses:
Lease operating expenses	6,542			31,818			13			—			38,373
Transportation, processing and gathering expenses	7,567			457			—			—			8,024
Production taxes	642			417			—			—			1,059
Depreciation, depletion and amortization	19,064			88,725			—			—			107,789
Write-down of oil and gas properties	15,858			231,645			350			—			247,853
Accretion expense	116			19,949			—			—			20,065
Salaries, general and administrative expenses	32,967			(199		)	—			—			32,768
Incentive compensation expense	9,649			—			—			—			9,649
Restructuring fees	10,389			—			—			—			10,389
Other operational expenses	33,845			280			6,082			—			40,207
Derivative expense, net	—			488			—			—			488
Total operating expenses	136,639			373,580			6,445			—			516,664
Loss from operations	(124,627		)	(215,734		)	(6,445		)	—			(346,806		)
Other (income) expenses:
Interest expense	32,840			—			—			—			32,840
Interest income	(416		)	—			—			—			(416		)
Other income	(59		)	(509		)	—			—			(568		)
Other expense	11			—			—			—			11
Loss from investment in subsidiaries	230,729			—			6,444			(237,173		)	—
Total other (income) expenses	263,105			(509		)	6,444			(237,173		)	31,867
Loss before taxes	(387,732		)	(215,225		)	(12,889		)	237,173			(378,673		)
Provision (benefit) for income taxes:
Current	(3,187		)	—			—			—			(3,187		)
Deferred	—			9,059			—			—			9,059
Total income taxes	(3,187		)	9,059			—			—			5,872
Net loss	$	(384,545	)	$	(224,284	)	$	(12,889	)	$	237,173		$	(384,545	)
Comprehensive loss	$	(395,112	)	$	(224,284	)	$	(12,889	)	$	237,173		$	(395,112	)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	10,854		$	208,238		$	—		$	—		$	219,092
Natural gas production	32,264			22,980			—			—			55,244
Natural gas liquids production	17,956			5,443			—			—			23,399
Other operational income	1,792			—			—			—			1,792
Derivative income, net	—			2,427			—			—			2,427
Total operating revenue	62,866			239,088			—			—			301,954
Operating expenses:
Lease operating expenses	10,087			44,919			—			—			55,006
Transportation, processing and gathering expenses	34,082			3,561			—			—			37,643
Production taxes	3,634			708			—			—			4,342
Depreciation, depletion and amortization	86,164			78,209			—			—			164,373
Write-down of oil and gas properties	670,537			—			45,169			—			715,706
Accretion expense	182			12,635			—			—			12,817
Salaries, general and administrative expenses	33,399			1			25			—			33,425
Incentive compensation expense	2,827			—			—			—			2,827
Other operational expenses	1,170			—			—			—			1,170
Total operating expenses	842,082			140,033			45,194			—			1,027,309
Income (loss) from operations	(779,216		)	99,055			(45,194		)	—			(725,355		)
Other (income) expenses:
Interest expense	20,816			21			—			—			20,837
Interest income	(147		)	(35		)	(6		)	—			(188		)
Other income	(320		)	(433		)	(3		)	—			(756		)
(Income) loss from investment in subsidiaries	(45,174		)	—			28,918			16,256			—
Total other (income) expenses	(24,825		)	(447		)	28,909			16,256			19,893
Income (loss) before taxes	(754,391		)	99,502			(74,103		)	(16,256		)	(745,248		)
Provision (benefit) for income taxes:
Deferred	(274,097		)	25,410			(16,267		)	—			(264,954		)
Total income taxes	(274,097		)	25,410			(16,267		)	—			(264,954		)
Net income (loss)	$	(480,294	)	$	74,092		$	(57,836	)	$	(16,256	)	$	(480,294	)
Comprehensive income (loss)	$	(522,953	)	$	74,092		$	(57,836	)	$	(16,256	)	$	(522,953	)



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net loss	$	(384,545	)	$	(224,284	)	$	(12,889	)	$	237,173		$	(384,545	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	19,064			88,725			—			—			107,789
Write-down of oil and gas properties	15,858			231,645			350			—			247,853
Accretion expense	116			19,949			—			—			20,065
Deferred income tax provision	—			9,059			—			—			9,059
Settlement of asset retirement obligations	—			(9,807		)	(899		)	—			(10,706		)
Non-cash stock compensation expense	4,682			—			—			—			4,682
Non-cash derivative expense	—			1,025			—			—			1,025
Non-cash interest expense	9,403			—			—			—			9,403
Other non-cash expense	—			—			6,081			—			6,081
Change in current income taxes	(3,187		)	—			—			—			(3,187		)
Non-cash loss from investment in subsidiaries	230,729			—			6,444			(237,173		)	—
Change in intercompany receivables/payables	(1,658		)	1,658			—			—			—
(Increase) decrease in accounts receivable	(8,471		)	19,109			(883		)	—			9,755
(Increase) decrease in other current assets	(5,316		)	—			33			—			(5,283		)
Increase (decrease) in accounts payable	2,226			(2,547		)	—			—			(321		)
Decrease in other current liabilities	(5,565		)	(355		)	—			—			(5,920		)
Other	(7,372		)	(508		)	—			—			(7,880		)
Net cash (used in) provided by operating activities	(134,036		)	133,669			(1,763		)	—			(2,130		)
Cash flows from investing activities:
Investment in oil and gas properties	(45,292		)	(133,670		)	(349		)	—			(179,311		)
Investment in fixed and other assets	(898		)	—			—			—			(898		)
Change in restricted funds	—			—			1,045			—			1,045
Investment in subsidiaries	—			—			717			(717		)	—
Net cash (used in) provided by investing activities	(46,190		)	(133,670		)	1,413			(717		)	(179,164		)
Cash flows from financing activities:
Proceeds from bank borrowings	477,000			—			—			—			477,000
Repayments of bank borrowings	(135,500		)	—			—			—			(135,500		)
Repayments of building loan	(189		)	—			—			—			(189		)
Deferred financing costs	(900		)	—			—			—			(900		)
Equity proceeds from parent	—			—			(717		)	717			—
Net payments for share-based compensation	(673		)	—			—			—			(673		)
Net cash provided by (used in) financing activities	339,738			—			(717		)	717			339,738
Effect of exchange rate changes on cash	—			—			(9		)	—			(9		)
Net change in cash and cash equivalents	159,512			(1		)	(1,076		)	—			158,435
Cash and cash equivalents, beginning of period	9,681			2			1,076			—			10,759
Cash and cash equivalents, end of period	$	169,193		$	1		$	—		$	—		$	169,194



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(480,294	)	$	74,092		$	(57,836	)	$	(16,256	)	$	(480,294	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	86,164			78,209			—			—			164,373
Write-down of oil and gas properties	670,537			—			45,169			—			715,706
Accretion expense	182			12,635			—			—			12,817
Deferred income tax (benefit) provision	(274,097		)	25,410			(16,267		)	—			(264,954		)
Settlement of asset retirement obligations	(14		)	(35,909		)	—			—			(35,923		)
Non-cash stock compensation expense	6,028			—			—			—			6,028
Non-cash derivative expense	—			7,931			—			—			7,931
Non-cash interest expense	8,737			—			—			—			8,737
Change in current income taxes	7,206			—			—			—			7,206
Non-cash (income) expense from investment in subsidiaries	(45,174		)	—			28,918			16,256			—
Change in intercompany receivables/payables	15,070			(24,802		)	9,732			—			—
Decrease in accounts receivable	16,968			6,079			—			—			23,047
Increase in other current assets	(1,895		)	—			(64		)	—			(1,959		)
(Increase) decrease in inventory	(2,415		)	2,415			—			—			—
Decrease in accounts payable	(500		)	(7,326		)	—			—			(7,826		)
Decrease in other current liabilities	(8,409		)	(311		)	—			—			(8,720		)
Other	(71		)	(433		)	—			—			(504		)
Net cash (used in) provided by operating activities	(1,977		)	137,990			9,652			—			145,665
Cash flows from investing activities:
Investment in oil and gas properties	(128,333		)	(124,506		)	(11,516		)	—			(264,355		)
Proceeds from sale of oil and gas properties, net of expenses	—			10,100			—			—			10,100
Investment in fixed and other assets	(727		)	—			—			—			(727		)
Change in restricted funds	177,647			—			1,828			—			179,475
Investment in subsidiaries	—			—			(9,684		)	9,684			—
Net cash provided by (used in) investing activities	48,587			(114,406		)	(19,372		)	9,684			(75,507		)
Cash flows from financing activities:
Proceeds from bank borrowings	5,000			—			—			—			5,000
Repayments of bank borrowings	(5,000		)	—			—			—			(5,000		)
Equity proceeds from parent	—			—			9,684			(9,684		)	—
Net payments for share-based compensation	(3,069		)	—			—			—			(3,069		)
Net cash (used in) provided by financing activities	(3,069		)	—			9,684			(9,684		)	(3,069		)
Effect of exchange rate changes on cash	—			—			78			—			78
Net change in cash and cash equivalents	43,541			23,584			42			—			67,167
Cash and cash equivalents, beginning of period	72,886			1,450			152			—			74,488
Cash and cash equivalents, end of period	$	116,427		$	25,034		$	194		$	—		$	141,655

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.

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.

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 August 2, 2016, we had total indebtedness of $1,428 million, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes, $341.5 million outstanding under our bank credit facility and $11.5 million outstanding under our Building Loan.

On March 10, 2016, we borrowed $385 million under our bank credit facility, which at the time, represented substantially all of the undrawn amount on our $500 million borrowing base. On April 13, 2016, the borrowing base under our bank credit facility was reduced by the lenders from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. In June 2016, however, we entered into the Amendment to our bank credit facility which, among other things, resulted in an increase of our borrowing base from $300 million to $360 million and relaxed certain financial covenants through December 31, 2016. In addition, the Amendment requires that we maintain minimum liquidity (as defined in the Amendment) of $125.0 million through January 15, 2017, imposes limitations on capital expenditures from June to December 2016 and provides for anti-hoarding cash provisions for amounts in excess of $50.0 million beginning after December 10, 2016. Upon execution of the Amendment, we repaid the balance of our borrowing base deficiency, resulting in approximately $360 million outstanding under the credit facility at that time. As of June 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. See "Liquidity and Capital Resources".

We have 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 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 certain holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes. To the extent the restructuring efforts result in an exchange of debt for equity, it may result in significant dilution for the existing stockholders. We cannot provide any assurances that we will be able to complete a private restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness.

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 and second quarters of 2016, we recognized ceiling test write-downs of our oil and gas properties of $351 million, $1,362 million, $129 million and $119 million, respectively. If NYMEX commodity prices remain at current levels (approximately $44 per Bbl of oil and $2.90 per MMBtu of natural gas), we would expect only minimal downward revisions of our estimated proved reserve quantities and would expect to recognize an additional ceiling test write-down between $0 and $100 million in the third quarter of 2016.

Bank Credit Facility – The level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. On June 14, 2016, we entered into the Amendment to the bank credit facility to, among other things, increase the borrowing base to $360 million from $300 million and revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to1 for the fiscal quarter ending September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter. See "Liquidity and Capital Resources". We were in compliance with all covenants under the bank credit facility and the indentures governing our outstanding notes as of June 30, 2016. However, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. 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.

BOEM Financial Assurance Requirements – The BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we and many other operators have been able to obtain an exemption from most bonding obligations based on financial net worth. 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 guidance to lessees at that time. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as $565 million. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $230 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations.

We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed plan would require approximately $16 million of incremental financial assurance or bonding for 2016, a majority of which may require cash collateral. Under the submitted plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Additionally, on July 14, 2016, BOEM issued a new NTL that augments requirements for the posting of additional financial assurance by offshore lessees. We are reviewing the new NTL and its potential impact to Stone.

The new NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the outer continental shelf ("OCS"), which will in turn force these operators to seek additional surety bonds and could, consequently, exceed the surety bond market’s current capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety may have about the priority of their lien on the operator's collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

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

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

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. At the time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of $29.2 million in May and June 2016. On June 14, 2016, we entered into the Amendment to the bank credit facility to, among other things, increase the borrowing base to $360 million, and on that date, we repaid $56.8 million in borrowings, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation. See "Bank Credit Facility" below. As of August 2, 2016, we had $341.5 million of outstanding borrowings and $18.3 million of outstanding letters of credit, leaving approximately $0.2 million of availability under the bank credit facility. We have $300 million of 2017 Convertible Notes that we need to restructure or repay by March 1, 2017 (see "Senior Notes" below). As of August 2, 2016, we had cash on hand of approximately $165.5 million.

Our capital expenditure budget for 2016 was set by the board of directors at $200 million, and assumed success in farming out the ENSCO 8503 deep water drilling rig to other operators for five to six months and the reduction in our working interests to acceptable levels on potential exploration wells to be drilled, or if unsuccessful, stacking the rig. The farm out subsidies and rig stacking expenses would be charges to our statement of operations as "Other operational expenses" and are expected to range between $40 million and $50 million. During the first two quarters of 2016, we successfully executed two separate rig farm out arrangements for the ENSCO 8503 with other operators. On June 24, 2016, our contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. Further, we agreed to provide Ensco the opportunity to perform certain drilling services commenced before December 31, 2019, and paid Ensco a $5 million deposit to be used against future drilling activities initiated before March 31, 2017, subject to extension in certain circumstances. The ENSCO 8503 deep water drilling rig contract included an operating day rate of $341,000 and was scheduled to expire in August 2017. To further reduce capital expenditures for 2016, we elected to temporarily stack the Pompano platform drilling rig in place. We currently expect to reinstate drilling operations in early 2017. The updated rig schedule and cost reduction efforts have decreased our projected 2016 capital expenditures to approximately $160 million to $170 million, excluding any deep water exploration drilling in the third and fourth quarters of 2016. The 2016 capital expenditure budget excludes material acquisitions and capitalized salaries, general and administrative (“SG&A”) expenses and interest as well as potential subsidy expense associated with rig farm outs, rig stacking charges and termination consideration.

Also, in late June 2016, Stone entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia. The interim agreement provides near-term relief for Stone by permitting Stone to resume profitable production and positive cash flow at the Mary field. The initial term of the interim agreement is through August 31, 2016 and it continues on a month to month basis thereafter unless terminated by either party. Subsequent to the execution of the interim agreement, production from much of the Mary field resumed in late June and averaged over 75 MMcfe per day in July, with total Appalachia volumes averaging 95 MMcfe per day in July. We expect daily production rates from Appalachia to reach over 125 MMcfe per day in the third quarter of 2016, resulting in increased cash flow along with increases in lease operating and transportation, processing and gathering expenses.

Based on our current outlook of commodity prices and our estimated production for 2016, we expect to fund our 2016 capital expenditures primarily with cash on hand from borrowings under our bank credit facility and expected cash flows from operating activities, as well as possible financings or asset sales. 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, 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 guidance to lessees at that time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM in finalizing and implementing our long-term tailored plan. We have submitted our tailored plan to BOEM and are awaiting its review and approval. Our proposed plan would require approximately $16 million of incremental financial assurance or bonding for 2016, a majority of which may require cash collateral. Under the submitted plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. Additionally, on July 14, 2016, BOEM issued a new NTL that augments requirements for the posting of additional financial assurances by offshore lessees. We are reviewing the new NTL and its potential impact to Stone.

Bank Credit Facility – On June 24, 2014, we entered into a 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. At that time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of $29.2 million in May and June 2016.

On June 14, 2016, we entered into the Amendment to the bank credit facility to (i) increase the borrowing base to $360 million from $300 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ending September 30, 2016, 9.50 to 1 for the fiscal quarter ending December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the Amendment) of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures from June through December 2016, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50.0 million to apply after December 10, 2016. Upon execution of the Amendment, we repaid $56.8 million in borrowings under the credit facility, bringing total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation. On August 2, 2016, we had $341.5 million of outstanding borrowings and $18.3 million of outstanding letters of credit, leaving $0.2 million of availability under the bank credit facility.

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

Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. In addition to the covenants discussed above, the bank credit facility provides that we must 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. The bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.

As of June 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes. However, we anticipate that the minimum liquidity requirement and other restrictions under the bank credit facility may prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes in March 2017. Further, we anticipate that we could exceed the Consolidated Funded Leverage financial covenant of 3.75 to 1 at the end of the first quarter of 2017, when the relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. 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 (see Overview). We have an interest payment obligation under our 2017 Convertible Notes of approximately $2.6 million, due on September 1, 2016, and one under our 2022 Notes of approximately $29.2 million, due on November 15, 2016.

Net cash (used in) provided by operating activities totaled ($2.1) million during the six months ended June 30, 2016 compared to $145.7 million during the comparable period in 2015. The decrease was primarily due to the decline in our hedge-effected oil, natural gas and NGL prices, the decline in natural gas and NGL production volumes, restructuring fees, rig subsidy and stacking expenses and the ENSCO 8503 termination fee, partially offset by a decline in lease operating and transportation, processing and gathering expenses. See "Results of Operations" for additional information relative to commodity prices, production and operating expense variances.

Net cash provided by financing activities totaled $339.7 million during the six months ended June 30, 2016, which primarily represents $477.0 million of borrowings under our bank credit facility less $135.5 million in repayments of borrowings under our bank credit facility. Net cash used in financing activities totaled $3.1 million during the six months ended June 30, 2015, which primarily represents net payments for share-based compensation. During the six months ended June 30, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility.

During the three months ended June 30, 2016, additions to oil and gas property costs of $40.2 million included $0.7 million of lease and property acquisition costs, $6.6 million of capitalized SG&A expenses (inclusive of incentive compensation) and $6.9 million of capitalized interest. During the six months ended June 30, 2016, additions to oil and gas property costs of $127.5 million included $1.3 million of lease and property acquisition costs, $12.4 million of capitalized SG&A expenses (inclusive of incentive compensation) and $14.3 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities.

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. On October 6, 2014, we entered into an agreement to contract the ENSCO 8503 deep water drilling rig for our multi-year deep water drilling program in the GOM. On June 24, 2016, our contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. Further, we agreed to provide Ensco the opportunity to perform certain drilling services commenced before December 31, 2019, and paid Ensco a $5 million deposit to be used against future drilling activities initiated before March 31, 2017, subject to extension in certain circumstances. The ENSCO 8503 deep water rig contract included an operating day rate of $341,000 and was scheduled to expire in August 2017. Other than the termination of the Ensco contract, there have been no material changes to this disclosure during the six months ended June 30, 2016.



	Three Months Ended June 30,
	2016		2015		Variance			% Change
Production:
Oil (MBbls)	1,548		1,534		14			1	%
Natural gas (MMcf)	5,100		12,581		(7,481		)	(59	)%
NGLs (MBbls)	244		794		(550		)	(69	)%
Oil, natural gas and NGLs (MBoe)	2,642		4,425		(1,783		)	(40	)%
Oil, natural gas and NGLs (MMcfe)	15,852		26,549		(10,697		)	(40	)%
Revenue data (in thousands): (1)
Oil revenue	$	72,711	$	111,585	$	(38,874	)	(35	)%
Natural gas revenue	12,553		26,907		(14,354		)	(53	)%
NGLs revenue	3,718		11,033		(7,315		)	(66	)%
Total oil, natural gas and NGL revenue	$	88,982	$	149,525	$	(60,543	)	(40	)%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	43.66	$	55.55	$	(11.89	)	(21	)%
Natural gas (per Mcf)	1.72		1.82		(0.10		)	(5	)%
NGLs (per Bbl)	15.24		13.90		1.34			10	%
Oil, natural gas and NGLs (per Boe)	30.31		26.93		3.38			13	%
Oil, natural gas and NGLs (per Mcfe)	5.05		4.49		0.56			12	%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	46.97	$	72.74	$	(25.77	)	(35	)%
Natural gas (per Mcf)	2.46		2.14		0.32			15	%
NGLs (per Bbl)	15.24		13.90		1.34			10	%
Oil, natural gas and NGLs (per Boe)	33.68		33.79		(0.11		)	—	%
Oil, natural gas and NGLs (per Mcfe)	5.61		5.63		(0.02		)	—	%
Expenses (per Mcfe):
Lease operating expenses	$	1.19	$	1.03	$	0.16		16	%
Transportation, processing and gathering expenses	0.45		0.75		(0.30		)	(40	)%
SG&A expenses (2)	1.26		0.62		0.64			103	%
DD&A expense on oil and gas properties	2.85		2.89		(0.04		)	(1	)%



	Six Months Ended June 30,
	2016		2015		Variance			% Change
Production:
Oil (MBbls)	3,183		3,156		27			1	%
Natural gas (MMcf)	11,946		23,738		(11,792		)	(50	)%
NGLs (MBbls)	608		1,477		(869		)	(59	)%
Oil, natural gas and NGLs (MBoe)	5,782		8,589		(2,807		)	(33	)%
Oil, natural gas and NGLs (MMcfe)	34,692		51,536		(16,844		)	(33	)%
Revenue data (in thousands): (1)
Oil revenue	$	132,986	$	219,092	$	(86,106	)	(39	)%
Natural gas revenue	27,726		55,244		(27,518		)	(50	)%
NGLs revenue	8,453		23,399		(14,946		)	(64	)%
Total oil, natural gas and NGL revenue	$	169,165	$	297,735	$	(128,570	)	(43	)%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	37.27	$	50.28	$	(13.01	)	(26	)%
Natural gas (per Mcf)	1.71		2.04		(0.33		)	(16	)%
NGLs (per Bbl)	13.90		15.84		(1.94		)	(12	)%
Oil, natural gas and NGLs (per Boe)	25.51		26.85		(1.34		)	(5	)%
Oil, natural gas and NGLs (per Mcfe)	4.25		4.47		(0.22		)	(5	)%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	41.78	$	69.42	$	(27.64	)	(40	)%
Natural gas (per Mcf)	2.32		2.33		(0.01		)	—	%
NGLs (per Bbl)	13.90		15.84		(1.94		)	(12	)%
Oil, natural gas and NGLs (per Boe)	29.26		34.66		(5.40		)	(16	)%
Oil, natural gas and NGLs (per Mcfe)	4.88		5.78		(0.90		)	(16	)%
Expenses (per Mcfe):
Lease operating expenses	$	1.11	$	1.07	$	0.04		4	%
Transportation, processing and gathering expenses	0.23		0.73		(0.50		)	(68	)%
SG&A expenses (2)	0.94		0.65		0.29			45	%
DD&A expense on oil and gas properties	3.04		3.14		(0.10		)	(3	)%

We follow the full cost method of accounting for oil and gas properties. During the three months ended June 30, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $118.6 million and $224.3 million, respectively. During the three months ended March 31, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $128.9 million and $491.4 million, respectively. During the three months ended March 31, 2016, we recognized a ceiling test write-down of our Canadian oil and gas properties, which were deemed fully impaired at the end of 2015, totaling $0.3 million. The write-downs did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity.

Production. During the three months ended June 30, 2016, total production volumes decreased to 15.9 Bcfe compared to 26.5 Bcfe produced during the comparable 2015 period, representing a 40% decrease. Oil production during the three months ended June 30, 2016 totaled approximately 1,548 MBbls compared to 1,534 MBbls produced during the comparable 2015 period. Natural gas production totaled 5.1 Bcf during the three months ended June 30, 2016 compared to 12.6 Bcf during the comparable 2015 period. NGL production during the three months ended June 30, 2016 totaled approximately 244 MBbls compared to 794 MBbls produced during the comparable

During the six months ended June 30, 2016, total production volumes decreased to 34.7 Bcfe compared to 51.5 Bcfe produced during the comparable 2015 period, representing a 33% decrease. Oil production during the six months ended June 30, 2016 totaled approximately 3,183 MBbls compared to 3,156 MBbls produced during the comparable 2015 period. Natural gas production totaled 11.9 Bcf during the six months ended June 30, 2016 compared to 23.7 Bcf during the comparable 2015 period. NGL production during the six months ended June 30, 2016 totaled approximately 608 MBbls compared to 1,477 MBbls produced during the comparable 2015 period. The decreases in natural gas and NGL production volumes during the six months ended June 30, 2016 were primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016.

Prices. Prices realized during the three months ended June 30, 2016 averaged $46.97 per Bbl of oil, $2.46 per Mcf of natural gas and $15.24 per Bbl of NGLs, compared to average realized prices of $72.74 per Bbl of oil, $2.14 per Mcf of natural gas and $13.90 per Bbl of NGLs during the comparable 2015 period. Prices realized during the six months ended June 30, 2016 averaged $41.78 per Bbl of oil, $2.32 per Mcf of natural gas and $13.90 per Bbl of NGLs, or 16% lower, on an Mcfe basis, than average realized prices of $69.42 per Bbl of oil, $2.33 per Mcf of natural gas and $15.84 per Bbl of NGLs during the comparable 2015 period. All unit pricing amounts include the cash settlement of effective hedging contracts.

We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. Our effective hedging transactions increased our average realized natural gas price by $0.74 per Mcf and increased our average realized oil price by $3.31 per Bbl during the three months ended June 30, 2016. During the three months ended June 30, 2015, our effective hedging transactions increased our average realized natural gas price by $0.32 per Mcf and increased our average realized oil price by $17.19 per Bbl. During the six months ended June 30, 2016, our effective hedging transactions increased our average realized natural gas price by $0.61 per Mcf and increased our average realized oil price by $4.51 per Bbl. During the six months ended June 30, 2015, our effective hedging transactions increased our average realized natural gas price by $0.29 per Mcf and increased our average realized oil price by $19.14 per Bbl.

Revenue. Oil, natural gas and NGL revenue was $89.0 million during the three months ended June 30, 2016 compared to $149.5 million during the comparable period of 2015. For the six months ended June 30, 2016 and 2015, oil, natural gas and NGL revenue totaled $169.2 million and $297.7 million, respectively. The decrease in total revenue for the three months ended June 30, 2016 was primarily due to a 40% decrease in production volumes and a 35% decrease in average realized oil prices from the comparable period of 2015. The decrease in total revenue for the six months ended June 30, 2016 was primarily due to a 33% decrease in production volumes and a 16% decrease in average realized prices on an equivalent basis from the comparable period of 2015.

Derivative Income/Expense. Net derivative expense for the three months ended June 30, 2016 totaled $0.6 million, comprised of $0.2 million of income from cash settlements and $0.8 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the three months ended June 30, 2015, net derivative expense totaled $0.7 million, comprised of $5.7 million of income from cash settlements and $6.4 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. Net derivative expense for the six months ended June 30, 2016 totaled $0.5 million, comprised of $0.5 million of income from cash settlements and $1.0 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the six months ended June 30, 2015, net derivative income totaled $2.4 million, comprised of $10.3 million of income from cash settlements and $7.9 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.

Expenses. Lease operating expenses during the three months ended June 30, 2016 and 2015 totaled $18.8 million and $27.4 million, respectively. For the six months ended June 30, 2016 and 2015, lease operating expenses totaled $38.4 million and $55.0 million, respectively. The decrease in lease operating expenses during the three and six months ended June 30, 2016 was primarily attributable to service cost reductions, the implementation of cost-savings measures, operating efficiencies and the shut-in of production at our Mary field from September 2015 until late June 2016. On a unit of production basis, lease operating expenses were $1.19 per Mcfe and $1.03 per Mcfe for the three months ended June 30, 2016 and 2015, respectively, and $1.11 per Mcfe and $1.07 per Mcfe for the six months ended June 30, 2016 and 2015, respectively. The unit cost of lease operating expenses increased during the three and six months ended June 30, 2016 from the comparable periods of 2015 as a result of decreased production volumes from Appalachia.

Transportation, processing and gathering expenses during the three months ended June 30, 2016 and 2015 totaled $7.2 million and $19.9 million, respectively, or $0.45 per Mcfe and $0.75 per Mcfe, respectively. For the six months ended June 30, 2016 and 2015, transportation, processing and gathering expenses totaled $8.0 million and $37.6 million, respectively, or $0.23 per Mcfe and $0.73 per Mcfe, respectively. The decrease was attributable to the shut-in of production at our Mary field from September 2015 until late June 2016 as well as the recoupment of previously paid transportation costs allocable to the Federal government's portion of certain of our deep water production, which amounted to approximately $4 million.

Other operational expenses for the three months ended June 30, 2016 and 2015 totaled $27.7 million and $1.5 million, respectively. Included in other operational expenses for the three months ended June 30, 2016 is a $20 million charge related to the termination of our deep water drilling rig contract with Ensco and approximately $7.5 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and the platform rig at Pompano. For the six months ended June 30, 2016 and 2015, other operational expenses totaled $40.2 million and $1.2 million, respectively. Included in other operational expenses for the six months ended June 30, 2016 is the $20 million Ensco contract termination charge, approximately $13.6 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Saxon Appalachian rig and the platform rig at Pompano and a $6.0 million cumulative foreign currency translation loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, which was reclassified from accumulated other comprehensive income.

SG&A expenses (exclusive of incentive compensation) for the three months ended June 30, 2016 were $20.0 million compared to $16.4 million for the three months ended June 30, 2015. For the six months ended June 30, 2016 and 2015, SG&A expenses (exclusive of incentive compensation) totaled $32.8 million and $33.4 million, respectively. On a unit of production basis, SG&A expenses were $1.26 per Mcfe and $0.62 per Mcfe for the three months ended June 30, 2016 and 2015, respectively. For the six months ended June 30, 2016 and 2015, SG&A expenses, on a unit of production basis, were $0.94 per Mcfe and $0.65 per Mcfe, respectively. The increase in SG&A expenses for the three months ended June 30, 2016 was primarily attributable to legal fees pertaining to Stone's pursuit of a claim for damages against a third party, partially offset by staff and other cost reductions.

For the three months ended June 30, 2016 and 2015, incentive compensation expense totaled $4.7 million and $1.3 million, respectively. For the six months ended June 30, 2016 and 2015, incentive compensation expense totaled $9.6 million and $2.8 million, respectively. The 2016 incentive compensation cash bonuses are calculated based on the achievement of certain strategic objectives for each quarter of 2016. Portions of the 2016 incentive cash bonuses replace amounts previously awarded to employees as stock-based compensation, reflected in SG&A expenses, resulting in higher incentive compensation expense in the 2016 periods as compared to the 2015 periods.

Interest expense for the three months ended June 30, 2016 totaled $17.6 million, net of $6.9 million of capitalized interest, compared to interest expense of $10.5 million, net of $10.8 million of capitalized interest, during the comparable 2015 period. For the six months ended June 30, 2016, interest expense totaled $32.8 million, net of $14.3 million of capitalized interest, compared to interest expense of $20.8 million, net of $21.6 million of capitalized interest, during the comparable 2015 period. The increase in interest expense was primarily the result of interest expense associated with the increased borrowings under our bank credit facility and a decrease in the amount of interest capitalized to oil and gas properties.

For the six months ended June 30, 2016 and 2015, we recorded an income tax provision (benefit) of $5.9 million and ($265.0) million, respectively. The income tax benefit recorded for the six months ended June 30, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs of our oil and gas properties. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined in the third quarter of 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. The change in the valuation allowance was recorded as an adjustment to income tax expense.

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.

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.

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 six months ended June 30, 2016, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $11.4 million impact on our revenues. Excluding the effects of hedging contracts, a 10% fluctuation in realized oil and natural gas prices would have had an approximate $14.7 million impact on our revenues. In order to manage our exposure to oil and natural gas price declines, we enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.

Our hedging policy currently provides that not more than 60% of our estimated production quantities can be hedged for any given year without the consent of the board of directors. We believe that our hedging positions as of August 2, 2016 have hedged approximately 28% of our estimated 2016 production from estimated proved reserves. Although we continue to monitor the marketplace for additional hedges for 2016 and beyond, continued weakness in commodity prices may impair our ability to secure hedges at prices we deem acceptable. See Part I, Item 1. Financial Statements – Note 4 – Derivative Instruments and Hedging Activities, of this Form 10-Q for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

We had total debt outstanding of $1,428 million at June 30, 2016, of which $1,087 million, or 76%, bears interest at fixed rates. The $1,087 million of fixed-rate debt is comprised of $300 million of the 2017 Convertible Notes, $775 million of the 2022 Notes and $12 million of the Building Loan. At June 30, 2016, the remaining $342 million of our outstanding debt bears interest at an adjustable interest rate and consists of borrowings outstanding under our bank credit facility. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources of this Form 10-Q. Borrowings under our bank credit facility may subject us to increased sensitivity to interest rate movements. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. At June 30, 2016, the weighted average interest rate under our bank credit facility was approximately 4.3% per annum.

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 June 30, 2016 at the reasonable assurance level.

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone, and related costs and attorney’s fees. Recently, the Louisiana Attorney General became a Plaintiff in all three Jefferson Parish cases. The Louisiana Attorney General’s intervention is not expected to affect the total damage amount sought from Stone in these cases.

In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. On November 12, 2015, the Plaquemines Parish Council passed a resolution instructing its attorneys to dismiss all 21 Coastal Zone Management suits filed by the Plaquemines Parish. On January 12, 2016, Stone moved to dismiss the action without prejudice on the basis of the resolution. On March 14, 2016, the Louisiana Attorney General became a Plaintiff in the case, after which the Plaquemines Parish Council rescinded its resolution, forcing Stone to withdraw its motion to dismiss. The Louisiana Attorney General’s intervention is not expected to affect the total damage amount sought from Stone in this case.

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

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.

On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock in order to increase the per share trading price of our common stock in order to regain compliance with the NYSE’s minimum share price requirement. We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the $1.00 per share average closing price requirement, although we remain non-compliant with the $50 million average market capitalization and stockholders’ equity requirements.

On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity deficiencies to the NYSE. After our submission of the business plan, the NYSE has 45 calendar days to review the plan to determine whether we have made reasonable demonstration of our ability to come into conformity with the relevant standards within the 18-month period. The NYSE will either accept the plan, at which time we would be subject to ongoing monitoring for compliance with the plan, or not accept the plan, at which time we would be subject to suspension and delisting proceedings. If the NYSE accepts the plan, during the 18-month cure period, our shares of common stock would continue to be listed and traded on the NYSE.

In addition to potentially commencing suspension or delisting procedures in respect of our common stock if the NYSE does not accept our business plan, our common stock could be delisted pursuant to Section 802.01 of the NYSE Listed Company Manual if the trading price of our common stock on the NYSE is abnormally low, which has generally been interpreted to mean at levels below $0.16 per share, and our common stock could also be delisted pursuant to Section 802.01 if our average market capitalization over a consecutive 30 day-trading period is less than $15 million. In these events, we would not have an opportunity to cure the 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.

On July 14, 2016, BOEM issued a Notice to Lessees and Operators (NTL) that augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The NTL, effective September 12, 2016, does away with the agency’s past practice of waiving supplemental bonding obligations where a company could demonstrate a certain level of financial strength. Instead, BOEM will allow companies to “self-insure,” but only up to 10% of a company’s “tangible net worth,” which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and if additional financial assurance must be provided. The NTL states that lessees may develop a “tailored plan” for posting any additional assurance that allows the lessee to phase-in any additional financial assurance required by BOEM. We intend to work with BOEM to develop a tailored plan for the provision of any new financial assurances required to be posted as a result of the new NTL. Compliance with the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, and limit activities in certain areas, or cause us to incur penalties or fines or to shut-in production at one or more of our facilities, or result in the suspension or cancellation of leases.

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 June 30, 2016:



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



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



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)



Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨



		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheet as of June 30, 2016 and December 31, 2015	1
	Condensed Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2016 and 2015	2
	Condensed Consolidated Statement of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2016 and 2015	3
	Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 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	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 4.	Controls and Procedures	37
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 6.	Exhibits	40
	Signatures	41
	Exhibit Index	42



	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



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



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



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


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



Gain (Loss) Recognized in Derivative Income (Expense) (In millions)
	Three Months Ended June 30,					Six Months Ended June 30,
Description	2016		2015			2016		2015
Commodity contracts:
Cash settlements	$	—	$	4.1		$	—	$	7.2
Change in fair value	—		(4.4		)	—		(5.3		)
Total gains (losses) on non-qualifying hedges	$	—	$	(0.3	)	$	—	$	1.9



	Six Months Ended June 30, 2016
	(In millions)
Asset retirement obligations as of the beginning of the period, including current portion	$	225.9
Liabilities incurred	2.1
Liabilities settled	(10.7		)
Accretion expense	20.1
Asset retirement obligations as of the end of the period, including current portion	$	237.4



	Fair Value Measurements at
	June 30, 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)	$	8.6	$	8.6	$	—	$	—
Derivative contracts	11.9		—		11.9		—
Total	$	20.5	$	8.6	$	11.9	$	—



	Hedging Contracts, net
	(In millions)
Balance as of January 1, 2016	$	2.0
Total gains/(losses) (realized or unrealized):
Included in earnings	1.1
Included in other comprehensive income	(1.9		)
Purchases, sales, issuances and settlements	(1.2		)
Transfers in and out of Level 3	—
Balance as of June 30, 2016	$	—
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at June 30, 2016	$	—


•	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 the resolution of pending litigation and government inquiry;


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


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


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


•	any expected results or benefits associated with our acquisitions;


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


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


•	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 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;


•	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;