UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________________

FORM 10-Q

__________________________________________________________

(Mark One)



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

For the quarterly period ended ~~September 30, 2016~~March 31, 2017



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

For the transition period from to

Commission File Number: 1-12074

__________________________________________________________

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



Delaware	72-1235413
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

625 E. Kaliste Saloom Road
Lafayette, Louisiana	70508
(Address of principal executive offices)	(Zip Code)

(337) 237-0410

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, ~~or a~~ smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated ~~filer”~~filer,” “smaller reporting company,” and ~~“smaller reporting~~“emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):



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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No ¨

As of ~~November 7, 2016,~~May 8, 2017, there were ~~5,688,410~~19,999,926 shares of the registrant’s common stock, par value $.01 per share, outstanding.

TABLE OF CONTENTS



		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheet as of ~~September 30, 2016~~March 31, 2017 and December 31, ~~2015~~2016	1
	Condensed Consolidated Statement of Operations for the ~~Three~~Period March 1, 2017 through March 31, 2017, the Period January 1, 2017 through February 28, 2017 and ~~Nine~~the Three Months Ended ~~September 30,~~March 31, 2016 ~~and 2015~~	2
	Condensed Consolidated Statement of Comprehensive Income (Loss) for the ~~Three~~Period March 1, 2017 through March 31, 2017, the Period January 1, 2017 through February 28, 2017 and ~~Nine~~the Three Months Ended ~~September 30,~~March 31, 2016 ~~and 2015~~	3
	Condensed Consolidated Statement of Changes in Stockholders' Equity for the Period March 1, 2017 through March 31, 2017, the Period January 1, 2017 through February 28, 2017 and the Year Ended December 31, 2016	4
	Condensed Consolidated Statement of Cash Flows for the ~~Nine~~Period March 1, 2017 through March 31, 2017, the Period January 1, 2017 through February 28, 2017 and the Three Months Ended ~~September 30,~~March 31, 2016 ~~and 2015~~	45
	Notes to Condensed Consolidated Financial Statements	56
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4339
Item 4.	Controls and Procedures	4440
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	4541
Item 1A.	Risk Factors	4542
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5243
Item 6.	Exhibits	5343
	Signatures	5445
	Exhibit Index	5546

PART I – FINANCIAL INFORMATION

~~Item~~ITEM 1. ~~Financial Statements~~FINANCIAL STATEMENTS

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)


	September 30, 2016			December 31, 2015			Successor			Predecessor
	(Unaudited)			(Note 1)			March 31, 2017			December 31, 2016
Assets							(Unaudited)			(Note 1)
Current assets:
Cash and cash equivalents	$	182,399		$	10,759		$	180,239		$	190,581
Restricted cash							74,068			—
Accounts receivable	44,063			48,031			35,380			48,464
Fair value of derivative contracts	6,261			38,576			3,398			—
Current income tax receivable	19,863			46,174			22,516			26,086
Other current assets	11,176			6,881			11,150			10,151
Total current assets	263,762			150,421			326,751			275,282
Oil and gas properties, full cost method of accounting:
Proved	9,564,561			9,375,898			677,977			9,616,236
Less: accumulated depreciation, depletion and amortization	(9,054,069		)	(8,603,955		)	(271,960		)	(9,178,442		)
Net proved oil and gas properties	510,492			771,943			406,017			437,794
Unevaluated	404,226			440,043			97,617			373,720
Other property and equipment, net	27,227			29,289			20,741			26,213
Fair value of derivative contracts							3,185			—
Other assets, net	29,800			18,473			16,993			26,474
Total assets	$	1,235,507		$	1,410,169		$	871,304		$	1,139,483
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	29,259		$	82,207		$	26,033		$	19,981
Undistributed oil and gas proceeds	7,439			5,992			1,428			15,073
Accrued interest	22,917			9,022			1,649			809
Asset retirement obligations	60,223			21,291			85,498			88,000
Current portion of long-term debt	292,795			—			412			408
Other current liabilities	10,903			40,712			17,500			18,602
Total current liabilities	423,536			159,224			132,520			142,873
Long-term debt	1,122,945			1,060,955			235,813			352,376
Asset retirement obligations	182,816			204,575			189,870			154,019
Other long-term liabilities	25,871			25,204			17,557			17,315
Total liabilities not subject to compromise							575,760			666,583
Liabilities subject to compromise							—			1,110,182
Total liabilities	1,755,168			1,449,958			575,760			1,776,765
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 30,000,000 shares; issued 5,605,525 and 5,530,232 shares, respectively	56			55
Treasury stock (1,658 shares, at cost)	(860		)	(860		)
Additional paid-in capital	1,657,028			1,648,687
Predecessor common stock ($.01 par value; authorized 30,000,000 shares; issued 5,610,020 shares)							—			56
Predecessor treasury stock (1,658 shares, at cost)							—			(860		)
Predecessor additional paid-in capital							—			1,659,731
Successor common stock ($.01 par value; authorized 60,000,000 shares; issued 19,996,828 shares)							200			—
Successor additional paid-in capital							554,957			—
Accumulated deficit	(2,179,803		)	(1,705,623		)	(259,613		)	(2,296,209		)
Accumulated other comprehensive income	3,918			17,952
Total stockholders’ equity	(519,661		)	(39,789		)	295,544			(637,282		)
Total liabilities and stockholders’ equity	$	1,235,507		$	1,410,169		$	871,304		$	1,139,483

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

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STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Successor			Predecessor
	2016			2015			2016			2015			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017			Three Months Ended March 31, 2016
Operating revenue:
Oil production	$	71,116		$	105,013		$	204,102		$	324,105		$	20,027		$	45,837		$	60,275
Natural gas production	15,601			17,367			43,327			72,611			2,210			13,476			15,173
Natural gas liquids production	6,666			5,980			15,119			29,379			777			8,706			4,735
Other operational income	1,044			1,392			1,737			3,184			149			903			356
Derivative income, net	—			2,444			—			4,871			2,646			—			138
Total operating revenue	94,427			132,196			264,285			434,150			25,809			68,922			80,677
Operating expenses:
Lease operating expenses	16,976			24,244			55,349			79,250			4,740			8,820			19,547
Transportation, processing and gathering expenses	10,633			18,208			18,657			55,851			144			6,933			841
Production taxes	835			2,052			1,894			6,394			65			682			481
Depreciation, depletion and amortization	58,918			61,936			166,707			226,309			15,847			37,429			61,558
Write-down of oil and gas properties	36,484			295,679			284,337			1,011,385			256,435			—			129,204
Accretion expense	10,082			6,498			30,147			19,315			2,901			5,447			9,983
Salaries, general and administrative expenses	15,425			19,552			48,193			52,977			3,322			9,629			12,754
Incentive compensation expense	2,160			794			11,809			3,621			—			2,008			4,979
Restructuring fees	5,784			—			16,173			—			288			—			953
Other operational expenses	9,059			442			49,266			1,612			661			530			12,527
Derivative expense, net	199			—			687			—			—			1,778			—
Total operating expenses	166,555			429,405			683,219			1,456,714			284,403			73,256			252,827
Loss from operations	(72,128		)	(297,209		)	(418,934		)	(1,022,564		)

Gain on Appalachia Properties divestiture													—			213,453			—

Income (loss) from operations													(258,594		)	209,119			(172,150		)
Other (income) expenses:
Interest expense	16,924			10,872			49,764			31,709			1,190			—			15,241
Interest income	(58		)	(47		)	(474		)	(235		)	(40		)	(45		)	(114		)
Other income	(272		)	(411		)	(840		)	(1,167		)	(131		)	(315		)	(298		)
Other expense	16			148			27			148			—			13,336			2
Total other expenses	16,610			10,562			48,477			30,455
Loss before income taxes	(88,738		)	(307,771		)	(467,411		)	(1,053,019		)
Reorganization items, net													—			(437,744		)	—
Total other (income) expense													1,019			(424,768		)	14,831
Income (loss) before income taxes													(259,613		)	633,887			(186,981		)
Provision (benefit) for income taxes:
Current	(991		)	—			(4,178		)	—			—			3,570			(1,074		)
Deferred	1,888			(15,806		)	10,947			(280,760		)	—			—			2,877
Total income taxes	897			(15,806		)	6,769			(280,760		)	—			3,570			1,803
Net loss	$	(89,635	)	$	(291,965	)	$	(474,180	)	$	(772,259	)
Basic loss per share	$	(16.01	)	$	(52.82	)	$	(84.90	)	$	(139.83	)
Diluted loss per share	$	(16.01	)	$	(52.82	)	$	(84.90	)	$	(139.83	)
Net income (loss)													$	(259,613	)	$	630,317		$	(188,784	)
Basic income (loss) per share													$	(12.98	)	$	110.99		$	(33.89	)
Diluted income (loss) per share													$	(12.98	)	$	110.99		$	(33.89	)
Average shares outstanding	5,600			5,528			5,585			5,523			19,997			5,634			5,571
Average shares outstanding assuming dilution	5,600			5,528			5,585			5,523			19,997			5,634			5,571

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,						Successor			Predecessor
	2016			2015			2016			2015			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017		Three Months Ended March 31, 2016
Net loss	$	(89,635	)	$	(291,965	)	$	(474,180	)	$	(772,259	)
Net income (loss)													$	(259,613	)	$	630,317	$	(188,784	)
Other comprehensive income (loss), net of tax effect:
Derivatives	(3,467		)	(5,353		)	(20,107		)	(45,691		)	—			—		(5,285		)
Foreign currency translation	—			(246		)	6,073			(2,567		)	—			—		6,074
Comprehensive loss	$	(93,102	)	$	(297,564	)	$	(488,214	)	$	(820,517	)
Comprehensive income (loss)													$	(259,613	)	$	630,317	$	(187,995	)

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY

(In thousands)

(Unaudited)



	Common Stock			Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity

Balance, December 31, 2015 (Predecessor)	$	55		$	(860	)	$	1,648,687		$	(1,705,623	)	$	17,952		$	(39,789	)
Net loss	—			—			—			(590,586		)	—			(590,586		)
Adjustment for fair value accounting of derivatives, net of tax	—			—			—			—			(24,025		)	(24,025		)
Adjustment for foreign currency translation, net of tax	—			—			—			—			6,073			6,073
Exercise of stock options, vesting of restricted stock and granting of stock awards	1			—			(732		)	—			—			(731		)
Amortization of stock compensation expense	—			—			11,776			—			—			11,776
Balance, December 31, 2016 (Predecessor)	56			(860		)	1,659,731			(2,296,209		)	—			(637,282		)
Net income	—			—			—			630,317			—			630,317
Exercise of stock options, vesting of restricted stock and granting of stock awards	—			—			(172		)	—			—			(172		)
Amortization of stock compensation expense	—			—			3,527			—			—			3,527
Balance, February 28, 2017 (Predecessor)	56			(860		)	1,663,086			(1,665,892		)	—			(3,610		)
Cancellation of Predecessor equity	(56		)	860			(1,663,086		)	1,665,892			—			3,610
Balance, February 28, 2017 (Predecessor)	—			—			—			—			—			—
Issuance of Successor common stock and warrants	200			—			554,866			—			—			555,066


Balance, February 28, 2017 (Successor)	200			—			554,866			—			—			555,066
Net loss	—			—			—			(259,613		)	—			(259,613		)
Amortization of stock compensation expense	—			—			91			—			—			91
Balance, March 31, 2017 (Successor)	$	200		$	—		$	554,957		$	(259,613	)	$	—		$	295,544

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,						Successor			Predecessor
	2016			2015			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017			Three Months Ended March 31, 2016
Cash flows from operating activities:
Net loss	$	(474,180	)	$	(772,259	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net income (loss)							$	(259,613	)	$	630,317		$	(188,784	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	166,707			226,309			15,847			37,429			61,558
Write-down of oil and gas properties	284,337			1,011,385			256,435			—			129,204
Accretion expense	30,147			19,315			2,901			5,447			9,983
Deferred income tax provision (benefit)	10,947			(280,760		)
Deferred income tax provision							—			—			2,877
Gain on sale of oil and gas properties							—			(213,453		)	—
Settlement of asset retirement obligations	(15,106		)	(59,826		)	(17,600		)	(3,641		)	(4,667		)
Non-cash stock compensation expense	6,407			9,163			17			2,645			2,312
Non-cash derivative expense	1,261			10,854
Non-cash derivative (income) expense							(2,484		)	1,778			192
Non-cash interest expense	14,278			13,210			—			—			4,635
Non-cash reorganization items							—			(458,677		)	—
Other non-cash expense	6,081			—			—			172			6,081
Change in current income taxes	21,584			7,211			—			3,570			(1,074		)
Decrease in accounts receivable	3,968			33,895			6,728			6,354			5,845
Increase in other current assets	(4,426		)	(1,090		)
(Increase) decrease in other current assets							964			(2,274		)	(185		)
Increase (decrease) in accounts payable	3,217			(11,592		)	3,015			(4,652		)	(2,138		)
Decrease in other current liabilities	(14,222		)	(6,753		)
Increase (decrease) in other current liabilities							1,672			(9,653		)	3,898
Investment in derivative contracts							(2,140		)	(3,736		)	—
Other	(8,107		)	(82		)	4,904			2,490			(298		)
Net cash provided by operating activities	32,893			198,980
Net cash provided by (used in) operating activities							10,646			(5,884		)	29,439
Cash flows from investing activities:
Investment in oil and gas properties	(200,622		)	(385,528		)	(5,584		)	(8,754		)	(129,859		)
Proceeds from sale of oil and gas properties, net of expenses	—			11,643			10,770			505,383			—
Investment in fixed and other assets	(1,231		)	(1,455		)	(2		)	(61		)	(496		)
Change in restricted funds	1,046			179,475			1,479			(75,547		)	1,045
Net cash used in investing activities	(200,807		)	(195,865		)
Net cash provided by (used in) investing activities							6,663			421,021			(129,310		)
Cash flows from financing activities:
Proceeds from bank borrowings	477,000			5,000			—			—			477,000
Repayments of bank borrowings	(135,500		)	(5,000		)	—			(341,500		)	(20,000		)
Repayments of building loan	(285		)	—			(36		)	(24		)	(95		)
Deferred financing costs	(900		)	—
Cash payment to noteholders							—			(100,000		)	—
Debt issuance costs							—			(1,055		)	—
Net payments for share-based compensation	(752		)	(3,127		)	—			(173		)	(650		)
Net cash provided by (used in) financing activities	339,563			(3,127		)	(36		)	(442,752		)	456,255
Effect of exchange rate changes on cash	(9		)	(2		)	—			—			(9		)
Net change in cash and cash equivalents	171,640			(14		)	17,273			(27,615		)	356,375
Cash and cash equivalents, beginning of period	10,759			74,488			162,966			190,581			10,759
Cash and cash equivalents, end of period	$	182,399		$	74,474		$	180,239		$	162,966		$	367,134

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~Note~~

NOTE 1 – FINANCIAL STATEMENT PRESENTATION

Interim Financial Statements

The condensed consolidated financial statements of Stone Energy Corporation ~~(“Stone”~~("Stone" or the "Company") and its subsidiaries as of ~~September 30, 2016~~March 31, 2017 (Successor) and for the periods from March 1, 2017 through March 31, 2017 (Successor), January 1, 2017 through February 28, 2017 (Predecessor) and the three ~~and nine month periods~~months ended ~~September 30,~~March 31, 2016 ~~and 2015~~(Predecessor) 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~~2016 (Predecessor) 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~~2016 (our ~~“2015~~"2016 Annual Report on Form ~~10-K”~~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~~2016 Annual Report on Form ~~10-K.~~10-K, though, as described below, such prior financial statements will not be comparable to the interim financial statements due to the adoption of fresh start accounting on February 28, 2017. For additional information, see Note 3 – Fresh Start Accounting. The results of operations for the ~~three and nine month periods ended September 30, 2016~~period from March 1, 2017 through March 31, 2017 (Successor) are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation.

Emergence from Voluntary Reorganization Under Chapter 11 Proceedings

On ~~May 27,~~December 14, 2016 (the "Petition Date"), the ~~board~~Company and its subsidiaries Stone Energy Offshore, L.L.C. ("Stone Offshore") and Stone Energy Holding, L.L.C. (together with the Company, the "Debtors")filed voluntary petitions (the "Bankruptcy Petitions") in the United States Bankruptcy Court for the Southern District of ~~directors~~Texas, Houston Division (the "Bankruptcy Court") seeking relief under the provisions of Chapter 11 of Title 11 ("Chapter 11") of the ~~Company approved a 1-for-10 reverse stock split~~United States Bankruptcy Code (the "Bankruptcy Code"). On February 15, 2017, the Bankruptcy Court entered an order (the "Confirmation Order") confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (the "Plan"), as modified by the ~~Company's issued~~Confirmation Order, and ~~outstanding shares of common stock. The reverse stock split was~~on February 28, 2017, the Plan became 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,~~(the "Effective Date") and the ~~common stock began trading on a split-adjusted basis when~~Debtors emerged from bankruptcy.

Upon emergence from bankruptcy, 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 decreasedCompany adopted fresh start accounting in ~~connection~~accordance with the ~~reverse stock split. Additionally, the overall and per share limitations~~provisions of Accounting Standards Codification ("ASC") 852, "Reorganizations", which resulted 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~~becoming a new entity for financial reporting purposes on the ~~current par value of $.01 per share for all shares of common stock.~~

All references in the financial statements and notes thereto to number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the 1-for-10 reverse stock split. Stockholders' equity reflects the reverse stock split by reclassifying from common stock to additional paid-in capital an amount equal to the par value of the reduction in the number of shares asEffective Date. As a result of the ~~reverse split.~~adoption of fresh start accounting, the Company’s unaudited condensed consolidated financial statements subsequent to February 28, 2017 will not be comparable to its financial statements prior to that date. See Note 3 – Fresh Start Accounting for further details on the impact of fresh start accounting on the Company’s unaudited condensed consolidated financial statements.

References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

~~Note 2 – Going Concern~~

The accompanying ~~condensed~~ consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these ~~condensed~~ consolidated financial statements. ~~As such,~~The significant decline in commodity prices since mid-2014 resulted in reduced revenue and cash flows and negatively impacted our liquidity position in 2015 and 2016. Additionally, 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 September 30, 2016~~at that time and the ~~current~~depressed commodity price environment ~~have~~ presented challenges ~~as they relate~~related 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 ended 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 September 30, 2016, however, thesuch indebtedness. The minimum liquidity requirement and other restrictions under ~~the credit facility may prevent us from being able~~our Pre-Emergence Credit Agreement (as defined in Note 2 – Reorganization) also presented challenges with respect to our ability to meet ~~our~~ interest payment ~~obligation~~obligations on the 7½7 1⁄2% Senior Notes due in 2022 (the ~~“2022 Notes”~~"2022 Notes") ~~in the fourth quarter of 2016~~ as well as the ~~subsequent~~ maturity of ~~our 1¾~~the 1 3⁄4% Senior Convertible Notes due ~~in March~~ 2017 (the ~~“2017~~"2017 Convertible ~~Notes”~~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.

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As a result of the impact to our financial position from the drastic decline in commodity prices and in consideration of the current level of our indebtedness, we engaged advisors to assist with the evaluation of various strategic alternatives to address our liquidity and capital structure (see ~~Note 12 – Restructuring Fees)~~. On October 20, 2016, we entered into a restructuring support agreement (the “RSA”) with certain holders of our 2017 Convertible Notes and our 2022 Notes (the "Noteholders") to support a restructuring on the terms of a pre-packaged plan of reorganization (the “Plan”). The RSA contemplates that we will file for voluntary relief under chapter 11 of the United States Bankruptcy Code (the "Bankruptcy Code") in a United States Bankruptcy Court (the "Bankruptcy Court") on or before December 9, 2016 to implement the Plan. Pursuant to the terms of the RSA, the Noteholders will receive (a) 95% of the common stock in reorganized Stone, (b) $225 million of new 7.5% second lien notes due 2022 and (c) $150 million of the net cash proceeds from the sale of Stone’s approximately 86,000 net acres in the Appalachia regions of Pennsylvania and West Virginia (the “Properties”) plus 85% of the net cash proceeds from the sale of the Properties in excess of $350 million, if any. Additionally, on October 20, 2016, we entered into a purchase and sale agreement (the “PSA”) with TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”). Pursuant to the terms of the PSA, we agreed to sell the Properties to Tug Hill for $360 million in cash, subject to customary purchase price adjustments. The consummation of the Plan will be subject to customaryThese conditions and other requirements, as well as the sale by Stone of the Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court. On November 4, 2016, we entered into an amendment to the RSA (the “RSA Amendment”) with the Noteholders pursuant to which (a) Stone will be obligated to, at any time upon the written request of the Noteholders or their counsel, provide in writing to counsel to the Noteholders the good faith estimate of Stone – together with documentation requested by the Noteholders or their counsel – of any cure amounts or other payment obligations of Stone arising or resulting from the assumption of executory contracts or unexpired leases on both a “per contract” basis and in the aggregate, (b) the Noteholders will have the option to terminate the RSA at any time that the Noteholders determine, in their sole discretion, that the total amount of all such payments exceeds an amount acceptable to the Noteholders, (c) the Noteholders will have the unilateral right to extend the automatic termination of the RSA if the restructuring transactions contemplated by the RSA are not consummated by the one-hundredth (100th) calendar day after the Company files for chapter 11 bankruptcy, and (d) solicitation will commence by November 10, 2016. For additional details on the RSA, RSA Amendment and PSA, see ~~Note 16 – Subsequent Events~~.

We cannot provide any assurances that we will be able to complete a restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness. We have been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached. While we expect to continue discussions and related negotiations with our bank credit facility lenders, there can be no assurance that an agreement will be reached. The conditions noted above and the uncertainties surrounding the restructuring, asset sales, renegotiation of our bank credit facility and chapter 11 bankruptcy proceedings raiseraised substantial doubt about our ability to continue as a going concern.

In order to address these issues, we worked with financial and legal advisors throughout 2016, structuring a plan of reorganization to address our liquidity and capital structure, and on December 14, 2016, the Debtors filed Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. In connection with our restructuring efforts, we sold our Appalachia Properties (as defined in Note 32 – ~~Earnings Per Share~~

~~The following table sets forth~~Reorganization). On February 15, 2017, the ~~calculation~~Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy. Upon emergence from bankruptcy, we eliminated approximately $1,110 million in principal amount of ~~basic and diluted weighted average shares~~ outstanding ~~and earnings per share for~~debt, resulting in remaining debt outstanding of approximately $236 million on the ~~indicated periods:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2016 2015 2016 2015
(In thousands, except per share data)
Income (numerator):
Basic:
Net loss $ (89,635 ) $ (291,965 ) $ (474,180 ) $ (772,259 )
Net income attributable to participating securities —
—
—
—
Net loss attributable to common stock - basic $ (89,635 ) $ (291,965 ) $ (474,180 ) $ (772,259 )
Diluted:
Net loss $ (89,635 ) $ (291,965 ) $ (474,180 ) $ (772,259 )
Net income attributable to participating securities —
—
—
—
Net loss attributable to common stock - diluted $ (89,635 ) $ (291,965 ) $ (474,180 ) $ (772,259 )
Weighted average shares (denominator):
Weighted average shares - basic 5,600
5,528
5,585
5,523
Dilutive effect of stock options —
—
—
—
Dilutive effect of convertible notes —
—
—
—
Weighted average shares - diluted 5,600
5,528
5,585
5,523
Basic loss per share $ (16.01 ) $ (52.82 ) $ (84.90 ) $ (139.83 )
Diluted loss per share $ (16.01 ) $ (52.82 ) $ (84.90 ) $ (139.83 )

Effective Date, consisting of $225 million of 7.5% Senior Second Lien Notes due 2022 (the "2022 Second Lien

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~~All~~Notes") and $11 million outstanding ~~stock options were considered antidilutive during~~under the three and nine months ended September 30, 2016 (approximately 12,900 shares) and during the three and nine months ended September 30, 2015 (approximately 14,400 shares) because we had net losses for such periods.

During the three months ended September 30, 2016 and 2015, approximately 12,900 shares and 1,832 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors. During the nine months ended September 30, 2016 and 2015, approximately 75,100 shares and 41,375 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors.

For the three and nine months ended September 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 nine months ended September 30, 2016 and 2015, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in4.20% Building Loan (the "Building Loan") (see Note 510 – Debt) ~~and therefore, such warrants were not dilutive for such periods. Based on the terms of the Purchased Call Options (as defined in~~ ~~Note 5 – Debt), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.~~

~~Note 4 – Derivative Instruments and Hedging Activities~~

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

The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and natural gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value and subsequent changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities.

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 November 7, 2016, two counterparties accounted for approximately 86% of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility.

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~~The following tables illustrate our derivative positions for calendar year 2016 as of November 7, 2016:~~

Fixed-Price Swaps (NYMEX)
Natural Gas Oil

Daily Volume
(MMBtus/d)

Swap Price
($)

Daily Volume
(Bbls/d)

Swap Price
($)
2016 10,000
4.110
1,000
49.75
2016 10,000
4.120
1,000
52.78
2016

1,000
90.00

Collar (NYMEX)
Oil

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

We previously discontinued hedge accounting for certain 2015 natural gas contracts, as it became no longer probable, subsequent to the sale of our non-core Gulf of Mexico ("GOM") conventional shelf properties, that our 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 September 30, 2016, we had accumulated other comprehensive income of $3.9 million, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of September 30, 2016. The $3.9 million of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.

~~Derivatives qualifying as hedging instruments:~~

~~The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at September 30, 2016 and December 31, 2015.~~

Fair Value of Derivatives Qualifying as Hedging Instruments at
September 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
$ 6.3

Current liabilities: Fair value
of derivative contracts
$ —

Long-term assets: Fair value
of derivative contracts
—

Long-term liabilities: Fair
value of derivative contracts
—
$ 6.3
$ —

Fair Value of Derivatives Qualifying as Hedging Instruments at
December 31, 2015
(In millions)
Asset Derivatives Liability Derivatives
Description Balance Sheet Location
Fair
Value
Balance Sheet Location
Fair
Value
Commodity contracts
Current assets: Fair value of
derivative contracts
$ 38.6

Current liabilities: Fair value
of derivative contracts
$ —

Long-term assets: Fair value
of derivative contracts
—

Long-term liabilities: Fair
value of derivative contracts
—
$ 38.6
$ —

The following tables disclose the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the three and nine month periods ended September 30, 2016 and 2015.

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Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended September 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 $ 2.3
$ 31.6

Operating revenue -
oil/natural gas production
$ 7.7
$ 39.9

Derivative income
(expense), net
$ (0.2 ) $ 1.2
Total $ 2.3
$ 31.6
$ 7.7
$ 39.9
$ (0.2 ) $ 1.2


~~(a)~~	For the three months ended September 30, 2016, effective hedging contracts increased oil revenue by $5.3 million and increased natural gas revenue by $2.4 million. For the three months ended September 30, 2015, effective hedging contracts increased oil revenue by $36.3 million and increased natural gas revenue by $3.6 million.

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Nine Months Ended September 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 $ (1.7 ) $ 35.7
Operating revenue -
oil/natural gas production $ 29.4
$ 107.1
Derivative income
(expense), net $ (0.7 ) $ 1.7
Total $ (1.7 ) $ 35.7
$ 29.4
$ 107.1
$ (0.7 ) $ 1.7


~~(a)~~	For the nine months ended September 30, 2016, effective hedging contracts increased oil revenue by $19.7 million and increased natural gas revenue by $9.7 million. For the nine months ended September 30, 2015, effective hedging contracts increased oil revenue by $96.8 million and increased natural gas revenue by $10.3 million.

~~Derivatives not qualifying as hedging instruments:~~

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

Gain (Loss) Recognized in Derivative Income (Expense)
(In millions)
Three Months Ended
September 30, Nine Months Ended
September 30,
Description 2016 2015 2016 2015
Commodity contracts:
Cash settlements $ —
$ 3.8
$ —
$ 11.0
Change in fair value —
(2.6 ) —
(7.9 )
Total gains (losses) on non-qualifying hedges $ —
$ 1.2
$ —
$ 3.1

~~Offsetting of derivative assets and liabilities:~~

Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. As of September 30, 2016 and December 31, 2015, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

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~~Note 5 – Debt~~

~~Our debt balances (net of related unamortized discounts and debt issuance costs) as of September 30, 2016 and December 31, 2015 were as follows:~~

September 30,
2016 December 31,
2015
(In millions)
1 3⁄4% Senior Convertible Notes due 2017
$ 292.4
$ 279.3
7 1⁄2% Senior Notes due 2022
770.4
770.0
Revolving credit facility 341.5
—
4.20% Building Loan 11.4
11.7
Total debt 1,415.7
1,061.0
Less: current portion of long-term debt (292.8 ) —
Long-term debt $ 1,122.9
$ 1,061.0

~~Current Portion of Long-Term Debt.~~ As of September 30, 2016, the current portion of long-term debt of $292.8 million consisted of $292.4 million of 2017 Convertible Notes and $0.4 million of principal payments due within one year on the Building Loan.

~~Revolving Credit Facility.~~ On June 24, 2014, we entered into 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 deficiency in six equal monthly installments, making the first payment of $29.2 million on May 13, 2016 and the second payment of $29.2 million on June 13, 2016.

On June 14, 2016, we entered into Amendment No. 3 (the "Amendment") to 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 ended 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 October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that we will file for voluntary relief under chapter 11 of the Bankruptcy Code on or before December 9, 2016 to implement the Plan (see ~~Note 16 – Subsequent Events~~). We have been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached. While we expect to continue discussions and related negotiations with the lenders under our bank credit facility, there can be no assurance that an agreement will be reached.

On September 30 and November 7, 2016, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving $6.0 million of availability under the bank credit facility. The weighted average interest rate under the bank credit facility was approximately 3.1% at September 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 September 30, 2016, the bank credit facility was guaranteed by our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”). On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore.

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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 September 30, 2016.

~~Senior Notes.~~ Our senior notes consist of $300 million of 2017 Convertible Notes and $775 million of 2022 Notes. On October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that we will file for voluntary relief under chapter 11 of the Bankruptcy Code on or before December 9, 2016 to implement the Plan (see ~~Note 16 – Subsequent Events~~).

~~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 September 30, 2016, our closing share price was $11.88 per share.

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

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.

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As of September 30, 2016, the carrying amount of the liability component of the 2017 Convertible Notes of $292.4 million was classified as a current liability. During the three and nine months ended September 30, 2016, we recognized $4.1 million and $12.0 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $1.1 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and nine months ended September 30, 2015, we recognized $3.8 million and $11.1 million, respectively, of interest expense for the amortization of the discount and $0.4 million and $1.1 million, respectively, of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the three and nine month periods ended September 30, 2016, we recognized $1.3 million and $3.9 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes. During the three and nine month periods ended September 30, 2015, we recognized $1.3 million and $3.9 million, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

~~2022 Notes.~~ On November 8, 2012 and November 27, 2013, respectively, we completed the public offering of $300 million and $475 million aggregate principal amount of our 2022 Notes. The 2022 Notes mature on November 15, 2022. We have an interest payment obligation under our 2022 Notes of approximately $29.2 million, due on November 15, 2016. The indenture governing the 2022 Notes provides a 30-day grace period that extends the latest date for making this cash interest payment to December 15, 2016 before an Event of Default occurs under the indenture, which would give the trustee or the holders of at least 25% in principal amount of the 2022 Notes the option to accelerate payment of the principal plus accrued and unpaid interest on the 2022 Notes.

~~Note 6 – Asset Retirement Obligations~~

~~The change in our asset retirement obligations during the nine months ended September 30, 2016 is set forth below:~~

Nine Months Ended
September 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 (15.1 )
Accretion expense 30.1
Asset retirement obligations as of the end of the period, including current portion $ 243.0

~~Note 7 – Income Taxes~~

As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of September 30, 2016, our valuation allowance totaled $343.1 million. Our effective tax rate for the nine months ended September 30, 2016 was 1.4%. This percentage differed from the federal statutory rate of 35.0% primarily due to the establishmentexecution of the ~~valuation allowance against deferred tax assets. Our assessment of~~Plan, there is no longer substantial doubt about 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~~Company’s ability to continue as a current income tax receivable of $19.9 million at September 30, 2016, which relates to expected tax refunds from the carryback of net operating losses to previous tax years. Additionally, we had $4.7 million of non-current income tax receivables at September 30, 2016 reflected in Other Assets, as the refunds are not expected to be received within twelve months.going concern.

Use of Estimates

~~Note 8 – Fair Value Measurements~~

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles ~~establish a fair value hierarchy~~requires our management to make estimates and assumptions that ~~has three levels based on~~affect the ~~reliability~~reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the ~~inputs used to determine~~financial statements and the ~~fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs~~reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and on various other ~~than quoted prices in active markets that are either directly or indirectly observable;~~assumptions and ~~Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.~~

~~As of September 30, 2016 and December 31, 2015, we held certain financial assets that are required~~information believed to be ~~measured at fair value on a recurring basis, including our commodity derivative instruments~~reasonable under the circumstances. Estimates and ~~our investments in marketable securities. We utilize~~assumptions about future events and their effects are uncertain and, accordingly, these estimates may change as new events occur, as additional information is obtained and as the ~~services of an independent third party to assist us in valuing our derivative instruments. We~~Company’s operating environment changes. Actual results could differ from those estimates. Estimates are used ~~the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts~~primarily when accounting for ~~our credit risk~~depreciation, depletion 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

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used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call portion of the collar. For a more detailed description of our derivative instruments, see ~~Note 4 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.~~

We had no liabilities measured at fair value on a recurring basis at September 30, 2016 and December 31, 2015. The following tables present our assets that are measured at fair value on a recurring basis at September 30, 2016 and December 31, 2015.

Fair Value Measurements at
September 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) $ 8.8
$ 8.8
$ —
$ —
Derivative contracts 6.3
—
6.3
—
Total $ 15.1
$ 8.8
$ 6.3
$ —

Fair Value Measurements at
December 31, 2015
Assets Total
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)
(In millions)
Marketable securities (Other assets) $ 8.5
$ 8.5
$ —
$ —
Derivative contracts 38.6
—
36.6
2.0
Total $ 47.1
$ 8.5
$ 36.6
$ 2.0

~~The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the nine months ended September 30, 2016.~~

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 September 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 September 30, 2016 $ —

The fair value of cash and cash equivalents approximated book value at September 30, 2016 and December 31, 2015. As of September 30, 2016 and December 31, 2015, the fair value of the liability component of the 2017 Convertible Notes was approximately $278.6 million and $217.1 million, respectively. As of September 30, 2016 and December 31, 2015, the fair value of the 2022 Notes was approximately $441.8 million and $271.3 million, respectively.

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The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see ~~Note 5 – Debt~~amortization ("DD&A") at inception, September 30, 2016 and December 31, 2015. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

~~Note 9 – Accumulated Other Comprehensive Income (Loss)~~

For the three months ended September 30, 2016, the only component of accumulated other comprehensive income (loss) related to our cash flow hedges. Changes in accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2016, were as follows (in millions):

Cash Flow
Hedges

Three Months Ended September 30, 2016
Beginning balance, net of tax $ 7.4

Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives 2.3

Income tax effect (0.8 )
Net of tax 1.5

Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production 7.7

Income tax effect (2.7 )
Net of tax 5.0

Other comprehensive loss, net of tax (3.5 )
Ending balance, net of tax $ 3.9

Cash Flow
Hedges

Foreign
Currency
Items
Total
Nine Months Ended September 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 (1.7 ) —
(1.7 )
Income tax effect 0.6
—
0.6
Net of tax (1.1 ) —
(1.1 )
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production 29.4
—
29.4
Other operational expenses —
(6.0 ) (6.0 )
Income tax effect (10.4 ) —
(10.4 )
Net of tax 19.0
(6.0 ) 13.0
Other comprehensive income (loss), net of tax (20.1 ) 6.0
(14.1 )
Ending balance, net of tax $ 3.9
$ —
$ 3.9

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

Cash Flow
Hedges

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

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

During the nine months ended September 30, 2016, we reclassified approximately $6.0 million of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC.

~~Note 10 – Investment in Oil and Gas Properties~~

~~Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of~~expense, unevaluated property costs, estimated future net cash flows from proved reserves, ~~(adjusted for hedges and excluding cash flows related~~costs to ~~estimated abandonment costs) to the net capitalized costs of proved~~abandon oil and gas properties, ~~net~~income taxes, accruals of ~~related deferred taxes. We refer to this comparison as a ceiling test. If the net~~ capitalized costs, ~~of proved oil~~operating costs and ~~gas properties exceed the~~production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated ~~discounted future net cash flows from proved reserves, we are required to write down the~~fair value of ~~our oil~~derivative contracts, contingencies and ~~gas properties to~~fair value estimates, including estimates of reorganization value, enterprise value and the fair value of the discounted cash flows. At September 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $36.5 million based on twelve-month average prices, net of applicable differentials, of $40.51 per Bbl of oil, $1.99 per Mcf of natural gas and $13.88 per Bbl of natural gas liquids ("NGLs"). The write-down at September 30, 2016 was decreased by $9.6 million as a result of hedges. 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 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. At March 31, 2016, the write-down of oil and gas properties also included

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$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.

~~Note 11 – Other Operational Expenses~~

Included in other operational expenses for the nine months ended September 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 nine months ended September 30, 2016 are approximately $15.3 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, an Appalachian drilling rig and the platform rig at Pompano, a $20 million charge related to the termination of our deep water drilling rig contract with Ensco and $7.5 million in charges related to the terminations of the Appalachian drilling rig contract and a contract with an offshore vessel provider.

~~Note 12 – Restructuring Fees~~

In March 2016, we retained financial and legal advisors to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We have been 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. On October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. We have also been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility. The legal and financial advisory costs associated with these restructuring efforts are included in the statement of operations as restructuring fees and totaled $5.8 million and $16.2 million for the three and nine months ended September 30, 2016, respectively.

~~Note 13 – Commitments and Contingencies~~

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management ("BOEM") stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s 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 $139 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.

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, 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, consistent with those procedures, BOEM has tentatively proposed an implementation timeline that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) “Self-Insurance” letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) “Proposal” letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) “Order” letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a “tailored plan” for posting additional security over a phased-in period of time, (B) within 60 days of such letter, provide additional security for “sole liability” properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan). BOEM tentatively expects to approve or deny tailored plans submitted by lessees on or around September 11, 2017, although extensions may be granted to companies actively working with BOEM to finalize tailored plans. We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are not eligible to self-insure any of our additional security obligations. We received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security will be required, and we intend to work with BOEM to adjust our previously submitted tailored plan for the provision of new financial assurances required to be postedrecorded as a result of the ~~new NTL. Our revised proposed plan would require approximately $35 million to $40 million~~adoption of incremental financial assurance or bonding for 2016 through 2017, a portion of which may require cash collateral. Under the revised plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM.fresh start accounting.

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~~Note 14 –~~ Recently Issued Accounting Standards

In ~~February 2016,~~May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, "Revenue from Contracts with Customers" to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 15, 2017. We expect to apply the modified retrospective approach upon adoption of this standard. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

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

In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ~~The standard is~~ASU 2016-09 became 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 inus on January 1, 2017. Under ASU 2016-09, the Company elected to not apply a forfeiture estimate and will recognize a credit in compensation expense to the ~~same period. We~~extent awards are ~~currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the~~forfeited. The implementation of this new standard ~~will~~did not have a material ~~effect.~~effect on our financial statements.

NOTE 2 – REORGANIZATION

On December 14, 2016, the Debtors filed Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy.

Prior to the filing of the Bankruptcy Petitions, the Debtors and certain holders of the 2017 Convertible Notes and the 2022 Notes (collectively, the "Notes" and the holders thereof, the "Noteholders") and the lenders (the "Banks") under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the "Pre-Emergence Credit Agreement"), entered into an Amended and Restated Restructuring Support Agreement (the "A&R RSA"). The A&R RSA contained certain covenants on the part of the Company and the Noteholders and Banks who are signatories to the A&R RSA, including that such Noteholders and Banks would support the Company's sale of Stone's producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the "Appalachia Properties") to TH Exploration III, LLC, an affiliate of Tug Hill, Inc. ("Tug Hill"), pursuant to the terms of a Purchase and Sale Agreement dated October 20, 2016, as amended on December 9, 2016 (the "Tug Hill PSA") for a purchase price of at least $350 million and approval of the Bankruptcy Court.Pursuant to the terms of the Tug Hill PSA, Stone agreed to sell the Appalachia Properties to Tug Hill for $360 million in cash, subject to customary purchase price adjustments.

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Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017, two additional bidders were allowed to participate in competitive bidding on the Appalachia Properties. On January 18, 2017, the Bankruptcy Court approved certain bidding procedures (the "Bidding Procedures") in connection with the sale of the Appalachia Properties. In ~~August 2016,~~accordance with the ~~FASB issued ASU 2016-15, "Statement~~Bidding Procedures, Stone conducted an auction for the sale of ~~Cash Flows (Topic 230)~~the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT Corporation, through its wholly-owned subsidiary EQT Production Company ("EQT"), ~~Classification~~with a final purchase price of ~~Certain Cash Receipts~~$527 million in cash, subject to customary purchase price adjustments and ~~Cash Payments~~"approval by the Bankruptcy Court, with an upward adjustment to ~~reduce diversity~~the purchase price of up to $16 million in ~~practice~~an amount equal to certain downward adjustments, as the prevailing bid. On February 9, 2017, the Company entered into a purchase and sale agreement with EQT (the "EQT PSA"), reflecting the terms of the prevailing bid and on February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We completed the sale of the Appalachia Properties to EQT on February 27, 2017 for a final purchase price of $527 million in ~~how certain~~ cash, ~~receipts~~subject to customary purchase price adjustments. At the close of the sale of the Appalachia Properties, the Tug Hill PSA was terminated, and the Company used a portion of the cash ~~payments are presented~~consideration received to pay Tug Hill a break-up fee and ~~classified~~expense reimbursements totaling approximately $11.5 million, which is recognized as other expense in the statement of ~~cash flows. The standard is effective~~operations for ~~public entities~~the period of January 1, 2017 through February 28, 2017 (Predecessor). See Note 7 – Divestiture for fiscal years beginning after December 15, 2017, and 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 alladditional information on the sale of the ~~amendments~~Appalachia Properties.

Upon emergence from bankruptcy, pursuant to the terms of the Plan, the following significant transactions occurred:

Shares of the Predecessor Company’s issued and outstanding common stock immediately prior to the Effective Date were cancelled, and on the Effective Date, reorganized Stone issued an aggregate of 20.0 million shares of new common stock (the "New Common Stock").

The Predecessor Company’s 2022 Notes and 2017 Convertible Notes were cancelled and the holders of such notes received their pro rata share of (a) $100 million of cash, (b) 19.0 million shares of the New Common Stock, representing 95% of the New Common Stock and (c) $225 million of 2022 Second Lien Notes.

The Predecessor Company’s common stockholders received their pro rata share of 1.0 million shares of the New Common Stock, representing 5% of the New Common Stock, and warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.

The Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement (as defined in ~~ASU 2016-15~~Note 10 – Debt). The obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement.

All claims of creditors with unsecured claims, other than the claims by the holders of the 2022 Notes and 2017 Convertible Notes, including vendors, were unaltered and paid in full in the ~~same period,~~ordinary course of business to the extent the claims were undisputed.

For further information regarding the equity and ~~any adjustments should be reflected as~~debt instruments of the ~~beginning of~~Predecessor Company and the fiscal year that includes that interim 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.Successor Company, see Note 4 – Stockholders’ Equity and Note 10 – Debt.

NOTE 3 – FRESH START ACCOUNTING

Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, "Reorganizations" as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. See Note 152 – Reorganization for the terms of the Plan. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. As described in Note 1 – Financial Statement Presentation, the new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

Reorganization Value

Under fresh start accounting, reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Upon application of fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values.

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The Company’s reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long-term debt and stockholders’ equity. In support of the Plan, the Company estimated the enterprise value of the core assets (as defined in the Plan) of the Successor Company to be in the range of $300 million to $450 million, which was subsequently approved by the Bankruptcy Court. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and public comparable company analyses. Based on the estimates and assumptions used in determining the enterprise value, the Company ultimately estimated the enterprise value of the Successor Company's core assets to be approximately $420 million.

Valuation of Assets

The Company’s principal assets are its oil and gas properties, which the Company accounts for under the full cost accounting method. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.

The fair value analysis performed by valuation experts was based on the Company’s estimates of reserves as developed internally by the Company’s reserve engineers. For purposes of estimating the fair value of the Company's proved, probable and possible reserves, an income approach was used which estimated fair value based on the anticipated cash flows associated with the Company's reserves, risked by reserve category and discounted using a weighted average cost of capital of 12.5%. The discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar market participants.

Future revenues were based upon forward strip oil and natural gas prices as of the emergence date, adjusted for differentials realized by the Company, and adjusted for a 2% annual escalation after 2021. Development and operating costs were based on the Company's recent cost trends adjusted for inflation. The discounted cash flow models also included estimates not typically included in proved reserves such as depreciation and income tax expenses. The proved reserve locations were limited to wells expected to be drilled in the Company's five year development plan.

As a result of this analysis, the Company concluded the fair value of its proved reserves was $380.8 million and the fair value of its probable and possible reserves was $16.8 million as of the Effective Date. The Company also reviewed its undeveloped leasehold acreage and inventory. An analysis of comparable market transactions indicated a fair value of undeveloped acreage and inventory totaling approximately $80.2 million. These amounts are reflected in the Fresh Start Adjustments item number 12 below. The fair value of the Company's asset retirement obligations was estimated at $290.1 million and was based on estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company's credit-adjusted risk free rate of 12%.

See further discussion in Fresh Start Adjustments below for details on the specific assumptions used in the valuation of the Company’s various other assets.

The following table reconciles the enterprise value per the Plan to the estimated fair value (for fresh start accounting purposes) of the Successor Company’s common stock as of February 28, 2017 (in thousands, except per share value):



	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets	371,607
Less: Fair value of debt	(236,261		)
Less: Fair value of warrants	(15,648		)
Fair value of Successor common stock	$	539,418

Shares issued upon emergence	20,000
Per share value	$	26.97

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The following table reconciles the enterprise value per the Plan to the estimated reorganization value as of the Effective Date (in thousands):



	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets	371,607
Plus: Asset retirement obligations (current and long-term)	290,067
Plus: Working capital and other liabilities	58,055
Reorganization value of Successor assets	$	1,139,449

Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

Condensed Consolidated Balance Sheet

The adjustments set forth in the following condensed consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and carried out by the Company (reflected in the column "Reorganization Adjustments") as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column "Fresh Start Adjustments"). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions or inputs. The following table reflects the reorganization and application of ASC 852 on our consolidated balance sheet as of February 28, 2017 (in thousands):

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	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
Assets
Current assets:
Cash and cash equivalents	$	198,571		$	(35,605	)	(1)	$	—			$	162,966
Restricted cash	—			75,547			(1)	—				75,547
Accounts receivable	42,808			9,301			(2)	—				52,109
Fair value of derivative contracts	1,267			—				—				1,267
Current income tax receivable	22,516			—				—				22,516
Other current assets	11,362			875			(3)	(124		)	(12)	12,113
Total current assets	276,524			50,118				(124		)		326,518
Oil and gas properties, full cost method of accounting:
Proved	9,633,907			(188,933		)	(1)	(8,774,122		)	(12)	670,852
Less: accumulated DD&A	(9,215,679		)	—				9,215,679			(12)	—
Net proved oil and gas properties	418,228			(188,933		)		441,557				670,852
Unevaluated	371,140			(127,838		)	(1)	(146,292		)	(12)	97,010
Other property and equipment, net	25,586			(101		)	(4)	(4,423		)	(13)	21,062
Fair value of derivative contracts	1,819			—				—				1,819
Other assets, net	26,516			(4,328		)	(5)	—				22,188
Total assets	$	1,119,813		$	(271,082	)		$	290,718			$	1,139,449
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	20,512		$	—			$	—			$	20,512
Undistributed oil and gas proceeds	5,917			(4,139		)	(1)	—				1,778
Accrued interest	266			—				—				266
Asset retirement obligations	92,597			—				—				92,597
Fair value of derivative contracts	476			—				—				476
Current portion of long-term debt	411			—				—				411
Other current liabilities	17,032			(195		)	(6)	—				16,837
Total current liabilities	137,211			(4,334		)		—				132,877
Long-term debt	352,350			(116,500		)	(7)	—				235,850
Asset retirement obligations	151,228			(8,672		)	(1)	54,914			(14)	197,470
Fair value of derivative contracts	653			—				—				653
Other long-term liabilities	17,533			—				—				17,533
Total liabilities not subject to compromise	658,975			(129,506		)		54,914				584,383
Liabilities subject to compromise	1,110,182			(1,110,182		)	(8)	—				—
Total liabilities	1,769,157			(1,239,688		)		54,914				584,383
Commitments and contingencies
Stockholders’ equity:
Common stock (Predecessor)	56			(56		)	(9)	—				—
Treasury stock (Predecessor)	(860		)	860			(9)	—				—
Additional paid-in capital (Predecessor)	1,660,810			(1,660,810		)	(9)	—				—
Common stock (Successor)	—			200			(10)	—				200
Additional paid-in capital (Successor)	—			554,866			(10)	—				554,866
Accumulated deficit	(2,309,350		)	2,073,546			(11)	235,804			(15)	—
Total stockholders’ equity	(649,344		)	968,606				235,804				555,066
Total liabilities and stockholders’ equity	$	1,119,813		$	(271,082	)		$	290,718			$	1,139,449

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Reorganization Adjustments (dollar amounts in thousands, except per share values)


1.	Reflects the net cash proceeds received from the sale of the Appalachia Properties in connection with the Plan and net cash payments made as of the Effective Date from implementation of the Plan:



Sources:
Net cash proceeds from sale of Appalachia Properties (a)	$	512,472
Total sources	512,472
Uses:
Cash transferred to restricted account (b)	75,547
Break-up fee to Tug Hill	10,800
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement	341,500
Repayment of 2017 Convertible Notes and 2022 Notes	100,000
Other fees and expenses (c)	20,230
Total uses	548,077
Net uses	$	(35,605	)

(a) The closing of the sale of the Appalachia Properties occurred on February 27, 2017, but as emergence was contingent on such closing, the effects of the transaction are reflected as reorganization adjustments. See Note 7 – Divestiture for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of $522,472 included cash consideration of $512,472 received at closing and a $10,000 indemnity escrow which was released subsequent to emergence from bankruptcy (see Reorganization Adjustment 2 below).

(b) Reflects the movement of $75,000 of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the provisions of the Amended Credit Agreement (as defined in Note 10 – Debt), and $547 held in a restricted cash account for certain cure amounts in connection with the Chapter 11 proceedings.


(c)	Other fees and expenses include approximately $15,180 of emergence and success fees, $2,600 of professional fees and $2,395 of payments made to seismic providers in settlement of their bankruptcy claims.


2.	Reflects a receivable for a $10,000 indemnity escrow with release delayed until emergence from bankruptcy, net of a $699 reimbursement to Tug Hill in connection with the sale of the Appalachia Properties (see Note 7 – Divestiture).


3.	Reflects the payment of a claim to a seismic provider as a prepayment/deposit.


4.	Reflects the sale of vehicles in connection with the sale of the Appalachia Properties.


5.	Reflects the write-off of $2,577 of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a $1,750 prepayment made to Tug Hill in October 2016.


6.	Reflects the accrual of $2,008 in expected bonus payments under the KEIP (as defined in Note 5 –Share–Based Compensation and Employee Benefit Plans) and a $395 termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of $2,598 in connection with the sale of the Appalachia Properties.


7.	Reflects the repayment of $341,500 of outstanding borrowings under the Pre-Emergence Credit Agreement and the issuance of $225,000 of 2022 Second Lien Notes as part of the settlement of the Predecessor Company 2017 Convertible Notes and 2022 Notes.


8.	Liabilities subject to compromise were settled as follows in accordance with the Plan:



1 ¾% Senior Convertible Notes due 2017	$	300,000
7 ½% Senior Notes due 2022	775,000
Accrued interest	35,182
Liabilities subject to compromise of the Predecessor Company	1,110,182
Cash payment to senior noteholders	(100,000		)
Issuance of 2022 Second Lien Notes to former holders of the senior notes	(225,000		)
Fair value of equity issued to unsecured creditors	(539,418		)
Fair value of warrants issued to unsecured creditors	(15,648		)
Gain on settlement of liabilities subject to compromise	$	230,116

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9.	Reflects the cancellation of the Predecessor Company’s common stock, treasury stock and additional paid-in capital.

10.

Reflects the issuance of Successor Company equity. In accordance with the Plan, the Successor Company issued 19.0 million shares of New Common Stock to the former holders of the 2017 Convertible Notes and the 2022 Notes and 1.0 million shares of New Common Stock to the Predecessor Company’s common stockholders. These amounts are subject to dilution by warrants issued to the Predecessor Company common stockholders, totaling approximately 3.5 million shares, with an exercise price of $42.04 per share and a term of four years. The fair value of the warrants was estimated at $4.43 per share using a Black-Scholes-Merton valuation model.

11.Reflects the cumulative impact of the reorganization adjustments discussed above:



Gain on settlement of liabilities subject to compromise	$	230,116
Professional and other fees paid at emergence	(10,648		)
Write-off of unamortized deferred financing costs	(2,577		)
Other reorganization adjustments	(1,915		)
Net impact to reorganization items	214,976
Gain on sale of Appalachia Properties	213,453
Cancellation of Predecessor Company equity	1,662,282
Other adjustments to accumulated deficit	(17,165		)
Net impact to accumulated deficit	$	2,073,546

Fresh Start Adjustments


12.	Fair value adjustments to oil and gas properties, associated inventory and unproved acreage. See above for a detailed discussion of the fair value methodology.


13.	Fair value adjustment for an office building owned by the Company. The income and sales comparison approaches were used in determining the fair value, using anticipated future earnings and an appropriate expected rate of return, as well as relying upon recent sales or offerings of similar assets.


14.	Fair value adjustments to the Company's asset retirement obligations using estimated plugging and abandonment costs as of the Effective Date, adjusted for inflation and discounted at the Successor Company's credit-adjusted risk free rate.


15.	Reflects the cumulative effect of the fresh start accounting adjustments discussed above.

Reorganization Items

Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as "Reorganization items, net" in the Company’s unaudited condensed consolidated statement of operations. The following table summarizes reorganization items, net (in thousands):



	Predecessor
	Period from January 1, 2017 through February 28, 2017
Gain on settlement of liabilities subject to compromise	$	230,116
Fresh start valuation adjustments	235,804
Reorganization professional fees and other expenses	(20,074		)
Write-off of deferred financing costs	(2,577		)
Other reorganization items	(5,525		)
Gain on reorganization items, net	$	437,744

The cash payments for reorganization items for the period from January 1, 2017 through February 28, 2017 include approximately $10.6 million of emergence and success fees and approximately $9.1 million of other reorganization professional fees and expenses paid on the Effective Date.

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NOTE 4 – STOCKHOLDERS' EQUITY

Common Stock

As discussed in Note 2 – Reorganization, upon emergence from bankruptcy, all existing shares of Predecessor common stock were cancelled, and the Successor Company issued an aggregate of 20.0 million shares of New ~~York~~Common Stock, ~~Exchange Compliance~~par value $0.01 per share, to the Predecessor Company's existing common stockholders and holders of the 2017 Convertible Notes and the 2022 Notes pursuant to the Plan.

Warrants

As discussed in Note 2 – Reorganization, the Predecessor Company's existing common stockholders received warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. The Company allocated approximately $15.6 million of the enterprise value to the warrants which is reflected in "Successor additional paid-in capital" on the unaudited condensed consolidated balance sheet at March 31, 2017 (Successor).

Registration Rights Agreement

On the Effective Date, the Company entered into a registration rights agreement (the "Registration Rights Agreement") with parties who received shares of New Common Stock upon the Effective Date (the "Holders") representing 5% or more of the New Common Stock outstanding on that date. The Registration Rights Agreement provides resale registration rights for the Holders’ Registrable Securities (as defined in the Registration Rights Agreement). Pursuant to the Registration Rights Agreement, Holders have customary underwritten offering and piggyback registration rights, subject to the limitations set forth in the Registration Rights Agreement. Under their underwritten offering registration rights, Holders have the right to demand the Company to effectuate the distribution of any or all of its Registrable Securities by means of an underwritten offering pursuant to an effective registration statement; provided, however, that the expected gross proceeds of such offering are equal to or greater than $20.0 million in the aggregate. The Company is not obligated to effect an underwritten demand notice upon certain circumstances, including within 180 days of closing an underwritten offering. Under their piggyback registration rights, if at any time the Company proposes to file a registration statement with respect to any firmly underwritten public offering of New Common Stock for its own account or for the account of any of its securityholders, subject to certain exceptions, the Company must give at least ten business days’ notice to all Holders of Registrable Securities to allow them to include a specified number of their shares in the offering. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in an offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as blackout periods.

NOTE 5 – SHARE–BASED COMPENSATION AND EMPLOYEE BENEFIT PLANS

Predecessor Awards

Immediately prior to emergence, the vesting of all Predecessor outstanding, unvested share-based awards for non-executive employees was accelerated and, as a result, all unrecognized compensation cost related to such awards was recognized, with approximately $1.7 million expensed as salaries, general and administrative ("SG&A") expense in the Predecessor Company statement of operations during the period from January 1, 2017 through February 28, 2017, and approximately $0.6 million capitalized into oil and gas properties.

Upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for a proportionate share of the 5% of New Common Stock, plus a proportionate share of the warrants for ownership of up to 15% of the Successor Company's common equity. Vesting continues in accordance with the applicable vesting provisions of the original awards. As of March 31, 2017, there was approximately $0.1 million of unrecognized compensation cost related to unvested restricted shares held by the Company's executives. The current weighted average remaining vesting period of such awards is approximately nine months. All other Predecessor Company executive share-based awards were cancelled upon emergence from bankruptcy.

The board of directors of the Predecessor Company received grants of stock, totaling 10,404 shares, during the period from January 1, 2017 through February 28, 2017, representing the pro-rated portion of their annual retainer for such period. The aggregate grant date value of such stock totaled approximately $69 thousand and was recognized as SG&A expense in the Predecessor Company statement of operations for the period from January 1, 2017 through February 28, 2017. Pursuant to the Plan, as of the Effective Date, all non-employee directors of the Predecessor Company ceased to serve on the Company's board of directors.

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2017 Equity Incentive Plan

On the Effective Date, pursuant to the Plan, the Stone Energy Corporation 2017 Long-Term Incentive Plan (the "2017 Incentive Plan") became effective, replacing the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015). The types of awards that may be granted under the 2017 Incentive Plan include stock options, restricted stock, restricted stock units, dividend equivalents and other forms of awards granted or denominated in shares of New Common Stock, as well as certain cash-based awards. The maximum number of shares of New Common Stock that may be issued or transferred pursuant to awards under the 2017 Incentive Plan is approximately 2.6 million.

Key Executive Incentive Plan

Pursuant to the terms of the Executive Claims Settlement Agreement approved by the Bankruptcy Court on January 10, 2017, the Company’s executive team (collectively, the "Executives") agreed to waive their claims related to the Company’s 2016 Performance Incentive Compensation Plan (the "2016 PICP"), and in exchange therefor, the Company adopted the Stone Energy Corporation Key Executive Incentive Plan ("KEIP"), in which the Executives are allowed to participate. Future payments to Executives under the KEIP are limited to approximately $2 million, or the equivalent of the target bonus under the 2016 PICP for the fourth quarter of 2016, to be paid in two equal installments. The first payment to Executives under the KEIP was paid subsequent to consummation of the bankruptcy cases, on April ~~29,~~24, 2017, and the second payment is to be made 90 days after the Company exits bankruptcy; provided, however, the Executives must have been employed upon consummation of the bankruptcy cases and the 90th day following the Company’s exit from bankruptcy or be terminated without cause or terminated for good reason in order to receive the respective bonus.

Successor Awards

On March 1, 2017, the board of directors of the Successor Company received grants of restricted stock units that are scheduled to vest in full on the day prior to the annual meeting of the Company’s stockholders in May 2018, subject to: (i) the director’s continued service on the board through the vesting date, and (ii) earlier vesting upon the occurrence of a change of control event or the termination of the director’s service due to death or removal from the board without cause. A total of 62,137 restricted stock units were granted with an aggregate grant date fair value of approximately $1.2 million.

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NOTE 6 – EARNINGS PER SHARE

On February 28, 2017, upon emergence from Chapter 11 bankruptcy, the Company's Predecessor equity was cancelled and new equity was issued. Additionally, the Predecessor Company's 2017 Convertible Notes were cancelled. See Note 2 – Reorganization and Note 4 – Stockholders' Equity for further details.

The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods (in thousands, except per share amounts):



	Successor			Predecessor
	Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017			Three Months Ended March 31, 2016
Income (numerator):
Basic:
Net income (loss)	$	(259,613	)	$	630,317		$	(188,784	)
Net income attributable to participating securities	—			(4,995		)	—
Net income (loss) attributable to common stock - basic	$	(259,613	)	$	625,322		$	(188,784	)
Diluted:
Net income (loss)	$	(259,613	)	630,317			$	(188,784	)
Net income attributable to participating securities	—			(4,995		)	—
Net income (loss) attributable to common stock - diluted	$	(259,613	)	$	625,322		$	(188,784	)
Weighted average shares (denominator):
Weighted average shares - basic	19,997			5,634			5,571
Dilutive effect of stock options	—			—			—
Dilutive effect of warrants	—			—			—
Dilutive effect of restricted stock units	—			—			—
Dilutive effect of convertible notes	—			—			—
Weighted average shares - diluted	19,997			5,634			5,571
Basic income (loss) per share	$	(12.98	)	$	110.99		$	(33.89	)
Diluted income (loss) per share	$	(12.98	)	$	110.99		$	(33.89	)

All outstanding stock options were considered antidilutive during the period from January 1, 2017 through February 28, 2017 (Predecessor) (approximately 10,400 shares) because the exercise price of the options exceeded the average price of our common stock for the applicable period. During the three months ended March 31, 2016 (Predecessor), all outstanding stock options were considered antidilutive (approximately 12,900 shares) because we had a net loss for such period. On February 28, 2017, upon emergence from bankruptcy, all outstanding stock options were cancelled. See Note 5 – Share-Based Compensation and Employee Benefit Plans.

On February 28, 2017, upon emergence from bankruptcy, the Predecessor Company's existing common stockholders received warrants to purchase common stock of the Successor Company. See Note 2 – Reorganization. For the period of March 1, 2017 through March 31, 2017 (Successor Company), all outstanding warrants (approximately 3,529,000) were anti-dilutive because we had a net loss for such period.

The Predecessor Company had no outstanding restricted stock units. The board of directors of the Successor Company received grants of restricted stock units on March 1, 2017. See Note 5 – Share-Based Compensation and Employee Benefit Plans. For the period of March 1, 2017 through March 31, 2017, all outstanding restricted stock units (approximately 62,000) were considered antidilutive because we had a net loss for such period.

For the period from January 1, 2017 through February 28, 2017 (Predecessor), the average price of our common stock was less than the effective conversion price for the 2017 Convertible Notes, resulting in no dilutive effect on the diluted earnings per share computation for such period. For the three months ended March 31, 2016 (Predecessor), the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had a net loss for such period. On February 28, 2017, upon emergence from bankruptcy, the 2017 Convertible Notes were cancelled. See Note 2 – Reorganization.

During the period from March 1, 2017 through March 31, 2017 (Successor) we had no issuances of shares of our common stock. During the periods from January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended March 31, 2016

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(Predecessor), approximately 47,390 shares and 50,131 shares of Predecessor Company common stock, respectively, were issued from authorized shares upon the granting of stock awards and the lapsing of forfeiture restrictions of restricted stock for employees and nonemployee directors.

NOTE 7 – DIVESTITURE

On February 27, 2017, we completed the sale of the Appalachia Properties to EQT for net consideration of approximately $522.5 million, representing gross proceeds of $527.0 million adjusted downward by approximately $4.5 million for purchase price adjustments for operations related to the Appalachia Properties after June 1, 2016, the effective date of the transaction. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company's cash payment obligations under the Plan. See Note 2 – Reorganization.

At December 31, 2016, the estimated proved oil and natural gas reserves associated with these assets totaled 18 MMBoe (million barrels of oil equivalent), which represented approximately 34% of our estimated proved oil and natural gas reserves on a volume equivalent basis. Upon closing, we no longer have assets or operations in Appalachia. Since accounting for the sale of these oil and gas properties as a reduction in the capitalized costs of oil and gas properties would have significantly altered the relationship between capitalized costs and reserves, we recognized a gain on the sale of approximately $213.5 million, computed as follows (in millions):



Net consideration received for sale of Appalachia Properties		$	522.5
Add:	Release of funds held in suspense	4.1
	Transfer of asset retirement obligations	8.7
	Other adjustments, net	2.6
Less:	Transaction costs	(7.1		)
	Carrying value of properties sold	(317.3		)
Gain on sale		$	213.5

The carrying value of the properties sold was determined by allocating total capitalized costs within the U.S. full cost pool between properties sold and properties retained based on their relative fair values.

NOTE 8 – INVESTMENT IN OIL AND GAS PROPERTIES

With the adoption of fresh start accounting, the Company recorded its oil and gas properties at fair value as of February 28, 2017. The Company's proved reserves, probable and possible reserves and unevaluated properties were assigned values of $380.8 million, $16.8 million and $80.2 million, respectively. See Note 3 – Fresh Start Accounting for a discussion of the valuation approach used.

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 designated cash flow hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows.

At March 31, 2017 (Successor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $256.4 million based on twelve-month average prices, net of applicable differentials, of $45.40 per Bbl of oil, $2.24 per Mcf of natural gas and $19.18 per Bbl of natural gas liquids ("NGLs"). The write-down at March 31, 2017 is reflected in the statement of operations of the Successor Company for the period of March 1, 2017 through March 31, 2017 and was primarily due to differences between the trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017. Weighted average commodity prices used in the determination of the fair value of our oil and gas properties for purposes of fresh start accounting were $56.01 per Bbl of oil, $2.52 per Mcf of natural gas and $14.18 per Bbl of NGLs, net of applicable differentials. Since none of our derivatives as of March 31, 2017 were designated as cash flow hedges (see Note 9 – Derivative Instruments and Hedging Activities), the write-down at March 31, 2017 was not affected by hedging.

At March 31, 2016 (Predecessor), 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 NGL. 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. The March 31, 2016 write-downs are reflected in the statement of operations of the Predecessor Company.

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NOTE 9 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. We do not enter into derivative transactions for trading purposes.

All derivatives are recognized as assets or liabilities on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked-to-market. If the derivative does not qualify or is not designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in earnings through derivative income (expense) in the statement of operations. If the derivative qualifies and is designated as a cash flow hedge, subsequent changes in the fair value of the derivative 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. Monthly settlements of ineffective hedges and derivatives not designated or that do not qualify for hedge accounting are recognized in earnings through derivative income (expense). The resulting cash flows from all monthly settlements are reported as cash flows from operating activities.

Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. A small portion of our cash flow hedges were ~~notified by~~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. We had no outstanding derivatives at December 31, 2016. With respect to our 2017 and 2018 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income (expense).

We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 2017 and 2018 oil production from the Gulf Coast Basin. 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 typically enter into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At May 8, 2017, our derivative instruments were with four counterparties, two of which accounted for approximately 74% of our contracted volumes. All of our outstanding derivative instruments are with lenders under our current bank credit facility.

Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the New York ~~Stock~~Mercantile Exchange ~~(“NYSE”~~("NYMEX") prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. 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. Settlements for our oil put contracts, fixed-price oil swaps and oil collar contracts are based on an average of the NYMEX closing price for West Texas Intermediate crude oil during the entire calendar month.

The following tables illustrate our derivative positions for calendar years 2017 and 2018 as of May 8, 2017:



		Put Contracts (NYMEX)
		Oil
		Cost of Put ($ in thousands)		Daily Volume (Bbls/d)	Price ($ per Bbl)
2017	February - December	$	752	1,000	$	50.00
2017	February - December	802		1,000	50.00
2018	January - December	2,183		1,000	54.00
2018	January - December	1,453		1,000	45.00

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		Fixed-Price Swaps (NYMEX)
		Oil
		Daily Volume (Bbls/d)	Swap Price ($ per Bbl)
2017	March - December	1,000	$	53.90
2018	January - December	1,000	52.50



		Collar Contracts (NYMEX)
		Oil
		Daily Volume (Bbls/d)	Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)
2017	March - December	1,000	$	50.00	$	56.45
2017	April - December	1,000	50.00		56.75

Derivatives not designated or not qualifying as hedging instruments

The following table discloses the location and fair value amounts of derivatives not designated or not qualifying as hedging instruments, as reported in our balance sheet, at March 31, 2017 (in millions). We had no outstanding hedging instruments at December 31, 2016 (Predecessor).



Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
March 31, 2017
(Successor)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	3.4	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	3.2		Long-term liabilities: Fair value of derivative contracts	—
		$	6.6		$	—

Gains or losses related to changes in fair value and cash settlements for derivatives not designated or not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations, for the period from January 1, 2017 through February 28, 2017 (Predecessor) and the period from March 1, 2017 through March 31, 2017 (Successor) (in millions).



Gain (Loss) Recognized in Derivative Income (Expense)
	Successor		Predecessor
	Period from March 1, 2017 through March 31, 2017		Period from January 1, 2017 through February 28, 2017
Description
Commodity contracts:
Cash settlements	$	0.2	$	—
Change in fair value	2.4		(1.8		)
Total gains (losses) on derivatives not designated or not qualifying as hedging instruments	$	2.6	$	(1.8	)

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Derivatives qualifying as hedging instruments

None of our derivative contracts outstanding as of March 31, 2017 (Successor) were designated as accounting hedges. We had no outstanding derivatives at December 31, 2016 (Predecessor). At March 31, 2016, we had outstanding derivatives that we were designated and qualified as hedging instruments. The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, during the three months ended March 31, 2016 (Predecessor) (in millions):



Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended March 31, 2016
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		Location	2016		Location	2016
Commodity contracts	$	4.6	Operating revenue - oil/natural gas production	$	12.8	Derivative income (expense), net	$	0.1
Total	$	4.6		$	12.8		$	0.1

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

Offsetting of derivative assets and liabilities

Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. As of March 31, 2017 (Successor), all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset. We had no outstanding derivative contracts at December 31, 2016 (Predecessor).

NOTE 10 – DEBT

Our debt balances (net of related unamortized discounts and debt issuance costs) as of March 31, 2017 and December 31, 2016 were as follows (in millions):



	Successor as of			Predecessor as of
	March 31, 2017			December 31, 2016
7 ½% Senior Second Lien Notes due 2022	$	225.0		$	—
1 ¾% Senior Convertible Notes due 2017	—			300.0
7 ½% Senior Notes due 2022	—			775.0
Predecessor revolving credit facility	—			341.5
4.20% Building Loan	11.2			11.3
Total debt	236.2			1,427.8
Less: current portion of long-term debt	(0.4		)	(0.4		)
Less: liabilities subject to compromise	—			(1,075.0		)
Long-term debt	$	235.8		$	352.4

Reorganization

On December 14, 2016, the Debtors filed Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code to pursue a prepackaged plan of reorganization. The 2017 Convertible Notes and 2022 Notes were impacted by the Chapter 11 process and were classified in the accompanying condensed consolidated balance sheet at December 31, 2016 as liabilities subject to compromise under the provisions of ASC 852, "Reorganizations". On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy. Upon emergence from bankruptcy, pursuant to the terms of the Plan, the Predecessor Company’s 2017 Convertible Notes and 2022 Notes were cancelled, the Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated, and the Company issued the 2022 Second Lien Notes.

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Current Portion of Long-Term Debt

As of March 31, 2017, the current portion of long-term debt of $0.4 million represented principal payments due within one year on the Building Loan.

Successor Revolving Credit Facility

On the Effective Date, pursuant to the terms of the Plan, the Company entered into the Fifth Amended and Restated Credit Agreement with the lenders party thereto and Bank of America, N.A. (the "Amended Credit Agreement"), as administrative agent and issuing lender, which amended and replaced the Company's Pre-Emergence Credit Agreement. The Amended Credit Agreement provides for a $200.0 million reserve-based revolving credit facility and matures on February 28, 2021.

The Company’s initial borrowing base under the Amended Credit Agreement has been set at $200.0 million with available borrowings thereunder of up to $150.0 million until the first borrowing base redetermination in November 2017. Interest on loans under the Amended Credit Agreement is calculated using the London Interbank Offering Rate ("LIBOR") or the base rate, at the election of the Company, plus, in each case, an applicable margin. The applicable margin is determined based on borrowing base utilization and ranges from 2.00% to 3.00% per annum for base rate loans and 3.00% to 4.00% per annum for LIBOR loans. At March 31, 2017, the Company had no outstanding borrowings and approximately $12.5 million of outstanding letters of credit, leaving approximately $137.5 million of availability under the Amended Credit Agreement.

The borrowing base under the Amended Credit Agreement is redetermined semi-annually, in May and November, by the lenders, in accordance with the lenders’ customary practices for oil and gas loans, with the first borrowing base redetermination to occur in November 2017. Subject to certain exceptions, the Amended Credit Agreement is required to be guaranteed by all of the material domestic direct and indirect subsidiaries of the Company. As of March 31, 2017, the Amended Credit Agreement is guaranteed by Stone Offshore. The Amended Credit Agreement is secured by substantially all of the Company’s and its subsidiaries’ assets.

Predecessor Revolving Credit Facility

On June 24, 2014, the Predecessor Company entered into the Pre-Emergence Credit Agreement with the lenders party thereto and Bank of America, N.A., as administrative agent and issuing lender, with commitments totaling $900 million (subject to borrowing base limitations). The borrowing base under the Pre-Emergence Credit Agreement prior to its amendment and restatement as the ~~average closing~~Amended Credit Agreement was $150 million. Interest on loans under the Pre-Emergence Credit Agreement was calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate was determined based on borrowing base utilization and ranged from 1.500% to 2.500%.

Prior to emergence from bankruptcy, the Predecessor Company had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit under the Pre-Emergence Credit Agreement. At emergence, the outstanding borrowings were paid in full and the $12.5 million of outstanding letters of credit were converted to obligations under the Amended Credit Agreement.

Building Loan

On November 20, 2015, we entered into an $11.8 million term loan agreement, the Building Loan, maturing on December 20, 2030. There were no changes to the terms of the Building Loan pursuant to the Plan.

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Successor 2022 Second Lien Notes

On the Effective Date, pursuant to the terms of the Plan, the Successor Company entered into an indenture by and among the Company, Stone Offshore as guarantor (the "Guarantor"), and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (the "2022 Second Lien Notes Indenture"), and issued $225.0 million of the Company’s 2022 Second Lien Notes pursuant thereto.

Interest on the 2022 Second Lien Notes will accrue at a rate of 7.50% per annum payable semi-annually in arrears on May 31 and November 30 of each year in cash, beginning November 30, 2017. The 2022 Second Lien Notes are secured on a second lien priority basis by the same collateral that secures the Amended Credit Agreement, including the Company’s oil and natural gas properties, and are guaranteed by the Guarantor. The 2022 Second Lien Notes mature on May 31, 2022. Pursuant to the terms of the Intercreditor Agreement (as defined below), the security interest in those assets that secure the 2022 Second Lien Notes and the related guarantee will be contractually subordinated to liens thereon that secure the Company’s Amended Credit Agreement and certain other permitted obligations as set forth in the 2022 Second Lien Notes Indenture. Consequently, the 2022 Second Lien Notes and the related guarantee will be effectively subordinated to the Amended Credit Agreement and such other permitted secured indebtedness to the extent of the value of such assets.

At any time prior to May 31, 2020, the Company may, at its option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Second Lien Notes issued under the 2022 Second Lien Notes Indenture at a redemption price of ~~our~~107.5% of the principal amount of the 2022 Second Lien Notes, plus accrued and unpaid interest to the redemption date, with an amount of cash equal to the net cash proceeds of certain equity offerings; provided that at least 65% of the aggregate principal amount of the 2022 Second Lien Notes remains outstanding after each such redemption. On or after May 31, 2020, the Company may redeem all or part of the 2022 Second Lien Notes at redemption prices (expressed as percentages of the principal amount) equal to (i) 105.625% for the twelve-month period beginning on May 31, 2020; (ii) 105.625% for the twelve-month period beginning on May 31, 2021; and (iii) 100.000% for the twelve-month period beginning May 31, 2022 and at any time thereafter, plus accrued and unpaid interest at the redemption date. In addition, at any time prior to May 31, 2020, the Company may redeem all or a part of the 2022 Second Lien Notes at a redemption price equal to 100% of the principal amount of the 2022 Second Lien Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest to the redemption date.

The 2022 Second Lien Notes Indenture contains covenants that restrict the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt and issue preferred stock; (ii) make payments or distributions on account of the Company’s or its restricted subsidiaries’ capital stock; (iii) sell assets; (iv) restrict dividends or other payments of the Company’s restricted subsidiaries; (v) create liens that secure debt; (vi) enter into transactions with affiliates, and (vii) merge or consolidate with another company. These covenants are subject to a number of important exceptions and qualifications. At any time when the 2022 Second Lien Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., and no Default or Event of Default (each as defined in the 2022 Second Lien Notes Indenture) has occurred and is continuing, many of these covenants will terminate.

The 2022 Second Lien Notes Indenture also provides for certain events of default. In the case of an event of default arising from certain events of bankruptcy, insolvency or reorganization with respect to the Company or any of the Company's restricted subsidiaries that is a significant subsidiary, or any group of the Company's restricted subsidiaries that, taken as a whole, would constitute a significant subsidiary of the Company, all outstanding 2022 Second Lien Notes will become due and immediately payable without further action or notice. If any other event of default occurs and is continuing, the trustee of the 2022 Second Lien Notes or the holders of at least 25% in aggregate principal amount of the then outstanding 2022 Second Lien Notes may declare all the 2022 Second Lien Notes to be due and payable immediately.

Intercreditor Agreement

On the Effective Date, Bank of America, N.A., as priority lien agent, The Bank of New York Mellon Trust Company, N.A., as second lien collateral agent, and The Bank of New York Mellon Trust Company, N.A., as the 2022 Second Lien Notes trustee, entered into an intercreditor agreement, which was acknowledged and agreed to by the Company and the Guarantor (the "Intercreditor Agreement") to govern the relationship of holders of the 2022 Second Lien Notes, the lenders under the Amended Credit Agreement and holders of other priority lien obligations, with respect to collateral and certain other matters.

Predecessor Senior Notes

2017 Convertible Notes. On March 6, 2012, the Predecessor Company 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 were convertible into cash, shares of our common stock ~~had fallen below $1.00~~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

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2017 Convertible Notes, which corresponded to an initial conversion price of approximately $42.65 per share ~~over~~of our common stock at the time of the issuance of the 2017 Convertible Notes. On June 10, 2016, we completed a ~~period~~1-for-10 reverse stock split with respect to our common stock and proportional adjustments were made to the conversion price and shares as they relate to the 2017 Convertible Notes, resulting in a conversion rate of ~~30 consecutive trading days, which is~~2.34449 shares of our common stock with a corresponding conversion price of $426.50 per share.

The 2017 Convertible Notes were due on March 1, 2017. Upon emergence from bankruptcy on February 28, 2017, pursuant to the ~~minimum average share price~~Plan, the $300 million of debt related to the 2017 Convertible Notes was cancelled. See Note 2 – Reorganization for ~~continued listing~~additional details.

During the three months ended March 31, 2016 (Predecessor), we recognized $3.9 million, $0.4 million and $1.3 million, respectively, of interest expense for the amortization of the discount, amortization of deferred financing costs and for the contractual interest coupon on the ~~NYSE under Section 802.01C~~2017 Convertible Notes.

2022 Notes. On November 8, 2012 and November 27, 2013, respectively, the Predecessor Company completed the public offering of $300 million and $475 million aggregate principal amount of our 2022 Notes. The 2022 Notes were scheduled to mature on November 15, 2022. Upon emergence from bankruptcy, pursuant to the Plan, the $775 million of debt related to the 2022 Notes was cancelled. See Note 2 – Reorganization for additional details.

NOTE 11 – ASSET RETIREMENT OBLIGATIONS

Upon emergence from bankruptcy, as discussed in Note 3 – Fresh Start Accounting, the Company adopted fresh start accounting which included the adjustment of asset retirement obligations to estimated fair values at February 28, 2017. The change in our asset retirement obligations during the period from January 1, 2017 through February 28, 2017 (Predecessor) and the period from March 1, 2017 through March 31, 2017 (Successor) is set forth below (in millions, inclusive of current portion):




Asset retirement obligations as of January 1, 2017 (Predecessor)	$	242.0
Liabilities settled	(3.6		)
Divestment of properties	(8.7		)
Accretion expense	5.4
Asset retirement obligations as of February 28, 2017 (Predecessor)	235.2
Fair value fresh start adjustment	54.9
Asset retirement obligations as of February 28, 2017 (Successor)	290.1
Liabilities settled	(17.6		)
Accretion expense	2.9
Asset retirement obligations as of March 31, 2017 (Successor)	$	275.4

NOTE 12 – INCOME TAXES

As a result of the ~~NYSE Listed~~significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of March 31, 2017 (Successor), our valuation allowance totaled $217.1 million. 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 $22.5 million at March 31, 2017 (Successor), which primarily relates to expected tax refunds from the carryback of net operating losses to previous tax years.

NOTE 13 – FAIR VALUE MEASUREMENTS

U.S. Generally Accepted Accounting Principles establish a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of March 31, 2017 (Successor) and December 31, 2016 (Predecessor), 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. The income approach is used in

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this determination utilizing the third party's 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 and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts were the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see Note 9 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

We had no liabilities measured at fair value on a recurring basis at March 31, 2017 (Successor). The following table presents our assets that are measured at fair value on a recurring basis at March 31, 2017 (Successor) (in millions).



	Fair Value Measurements
	Successor as of
	March 31, 2017
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	9.0	$	9.0	$	—	$	—
Derivative contracts	6.5		—		0.8		5.7
Total	$	15.5	$	9.0	$	0.8	$	5.7

We had no liabilities measured at fair value on a recurring basis at December 31, 2016 (Predecessor). The following table presents our assets that are measured at fair value on a recurring basis at December 31, 2016 (Predecessor) (in millions).



	Fair Value Measurements
	Predecessor as of
	December 31, 2016
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	8.7	$	8.7	$	—	$	—
Total	$	8.7	$	8.7	$	—	$	—

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The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period from March 1, 2017 through March 31, 2017 (Successor) and the period from January 1, 2017 through February 28, 2017 (Predecessor).



	Hedging Contracts, net
	(in millions)
Balance as of January 1, 2017 (Predecessor)	$	—
Total gains/(losses) (realized or unrealized):
Included in earnings	(0.6		)
Included in other comprehensive income	—
Purchases, sales, issuances and settlements	3.7
Transfers in and out of Level 3	—
Balance as of February 28, 2017 (Successor)	3.1
Total gains/(losses) (realized or unrealized):
Included in earnings	0.5
Included in other comprehensive income	—
Purchases, sales, issuances and settlements	2.1
Transfers in and out of Level 3	—
Balance as of March 31, 2017 (Successor)	$	5.7
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at March 31, 2017	$	—

The fair value of cash and cash equivalents approximated book value at March 31, 2017 and December 31, 2016. Upon emergence from bankruptcy on February 28, 2017, the 2017 Convertible Notes and 2022 Notes were cancelled, and the Company ~~Manual.~~ issued the 2022 Second Lien Notes. As of December 31, 2016, the fair value of the liability component of the 2017 Convertible Notes was approximately $293.5 million. As of December 31, 2016, the fair value of the 2022 Notes was approximately $465.0 million. As of March 31, 2017, the fair value of the 2022 Second Lien Notes was approximately $219.9 million.

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

On February 28, 2017, the Company emerged from bankruptcy and adopted fresh start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon the adoption of fresh start accounting, the Company's assets and liabilities were recorded at their fair values as of the fresh start reporting date, February 28, 2017. See Note 3 – Fresh Start Accounting for a detailed discussion of the fair value approaches used by the Company. The inputs utilized in the valuation of our most significant asset, our oil and gas properties, included mostly unobservable inputs, which fall within Level 3 of the fair value hierarchy.

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NOTE 14 – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts, and accordingly, changes in the fair value of the derivative were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. We had no outstanding derivative contracts at December 31, 2016.

During the periods from March 1, 2017 through March 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor), we entered into various commodity derivative contracts (see Note 9 – Derivative Instruments and Hedging Activities). With respect to our 2017 and 2018 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income (expense).

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



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

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

NOTE 15 – OTHER OPERATIONAL EXPENSES

Included in other operational expenses for the three months ended March 31, 2016 (Predecessor) 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 14 – Accumulated Other Comprehensive Income (Loss). Also included in other operational expenses for the three months ended March 31, 2016 (Predecessor) are approximately $6.1 million of rig subsidy charges related to the farm out of the ENSCO 8503 deep water drilling rig and stacking charges related to an Appalachian drilling rig.

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NOTE 16 – COMMITMENTS AND CONTINGENCIES

Chapter 11 Proceedings

On December 14, 2016, the Debtorsfiled Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect pre-petition liabilities or to exercise control over the property of the Debtors. On February 15, 2017, the Bankruptcy Court entered the Confirmation Order confirming the Plan, as modified by the Confirmation Order, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy, with the bankruptcy cases then being closed by Final Decree Closing Chapter 11 Cases and Terminating Claims Agent Services entered by the Bankruptcy Court on April 20, 2017. For additional information on the bankruptcy proceedings, see Note 1 – Financial Statement Presentation and Note 2 – Reorganization.

Other Commitments and Contingencies

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management ("BOEM") stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such 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 towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $118 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates. The bonds represent guarantees by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements.

In July 2016, BOEM issued a Notice to Lessees ("NTL"), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL also provides new procedures for how BOEM determines a lessee’s decommissioning obligations.

We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are not eligible to self-insure any of our additional security obligations. We received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required, and we are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of the Bureau of Safety and Environmental Enforcement ("BSEE"). The September 30, 2016 Self-Insurance determination letter was rescinded by BOEM on March 24, 2017. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. The revised proposed plan may require potentially $30 million to $60 million of incremental financial assurance or bonding for non-sole liability properties by the end of 2017 or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL. Under the revised proposed plan, additional financial assurance would be required for subsequent years. There is no assurance that this tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan.

NOTE 17 – NEW YORK STOCK EXCHANGE COMPLIANCE

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. 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. The~~ NYSE, ~~accepted the plan~~and on August 4, 2016, the NYSE accepted the Plan. We submitted our quarterly updates to the business plan for the second, third and fourth quarters of 2016, each of which was accepted by the NYSE. Since March 1, 2017, the first day of trading subsequent to the effective date of the Company's plan of reorganization, the Successor Company has maintained a market capitalization above $50 million. The NYSE will continue to review the Company on a quarterly basis for compliance with the ~~plan. Upon acceptance of~~business plan until we have demonstrated compliance with the ~~plan by the NYSE, and after two consecutive quarters of sustained market capitalization above $50 million, we would no longer be non-compliant with the~~average global market capitalization and stockholders' equity requirements. During the 18-month cure period, our shares of common stock will continue to be listed and traded on the NYSE, unless we experience other circumstances that subject us to delisting, including an abnormally low market capitalization. If we fail to meet the material aspects of the plan or any of the quarterly milestones, the NYSE will review the circumstances causing the variance and determine whether such variance warrants commencement of suspension and delisting procedures. Upon a delisting from the NYSE, we would commence trading on the OTC Pink. On September 20, 2016, we submitted our quarterly update to the business planlisting requirements for ~~the second quarter of 2016, and the NYSE notified us that it accepted the quarterly update on September 22, 2016. We expect to submit our third quarter 2016 plan update to the NYSE by mid-December.~~two consecutive quarters.

~~Note 16 – Subsequent Events~~

~~Restructuring Support Agreement~~

On October 20, 2016, the Company entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that the Company will file for voluntary relief under chapter 11 of the Bankruptcy Code in a Bankruptcy Court on or before December 9, 2016 to implement the Plan in accordance with the term sheet annexed to the RSA (the “Term Sheet”).

The RSA would become effective upon (i) execution by the Company and Noteholders holding, in the aggregate, at least two-thirds of the outstanding aggregate principal amount of the Notes, and (ii) Stone having entered into a PSA for the sale of Properties for a cash

~~Table of Contents~~

purchase price of at least $350 million. Both conditions were satisfied, with Noteholders holding approximately 85.4% of the aggregate principal amount of the Notes executing the RSA and Stone signing the PSA, as indicated below. Pursuant to the terms of the RSA and the Term Sheet, Noteholders and other interest holders will receive treatment under the Plan summarized as follows:

The Noteholders will receive their pro rata share of (a) $150 million of the net cash proceeds from the sale of the Properties plus 85% of the net cash proceeds from the sale of the Properties in excess of $350 million, if any, (b) 95% of the common stock in reorganized Stone and (c) $225 million of new 7.5% second lien notes due 2022.

Existing common stockholders of Stone will receive their pro rata share of 5% of the common stock in reorganized Stone and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants.

All claims of creditors with unsecured claims other than claims by the Noteholders, including vendors, shall be unaltered and will be paid in full in the ordinary course of business to the extent such claims are undisputed. Stone estimates that such unsecured claims are in the range of approximately $17 million to $27 million in the aggregate.

Holders of claims arising on account of Stone’s existing revolving credit facility will receive (a)(i) if such holders vote, as a class, to accept the Plan, commitments on terms set forth on Exhibit 1(a) to the Term Sheet, on a pro rata basis, under an amended revolving credit facility, or (ii) if such holders, as a class, do not vote to accept the Plan (or are deemed to reject the Plan), a term loan on terms set forth on Exhibit 1(b) to the Term Sheet, or (b) such other treatment as is acceptable to the Company and the Noteholders and consistent with the Bankruptcy Code, including, but not limited to, section 1129(b) of the Bankruptcy Code.

~~Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan.~~

The Company has been engaged in discussions and has exchanged proposals with the lenders under its bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached. While the Company expects to continue discussions and related negotiations with the lenders under its bank credit facility, there can be no assurance that an agreement will be reached.

The RSA contains certain covenants on the part of the Company and the Noteholders who are signatories to the RSA, including that such Noteholders will vote in favor of the Plan, support the sale of the Properties and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the RSA. The consummation of the Plan will be subject to customary conditions and other requirements, as well as the sale by Stone of the Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court. The RSA also provides for termination by each party, or by either party, upon the occurrence of certain events, including without limitation, termination by the Noteholders upon the failure of the Company to achieve certain milestones set forth in Schedule 1 to the RSA.

Assuming implementation of the Plan, Stone expects that it will eliminate approximately $850 million in principal of outstanding debt and reduce its annual interest payment burden by approximately $46 million.

~~On November 4, 2016 the Company and the Noteholders entered into the RSA Amendment pursuant to which:~~

Stone will be obligated to, at any time upon the written request of the Noteholders or their counsel, provide in writing to counsel to the Noteholders the good faith estimate of Stone – together with documentation requested by the Noteholders or their counsel – of any cure amounts or other payment obligations of Stone arising or resulting from the assumption of executory contracts or unexpired leases on both a “per contract” basis and in the aggregate;

The Noteholders will have the option to terminate the RSA at any time that the Noteholders determine, in their sole discretion, that the total amount of all such payments exceeds an amount acceptable to the Noteholders;

The Noteholders will have the unilateral right to extend the automatic termination of the RSA if the restructuring transactions contemplated by the RSA are not consummated by the one-hundredth (100th) calendar day after the Company files for chapter 11 bankruptcy; and

~~Solicitation of noteholders in support of the Plan will commence by November 10, 2016.~~

Although the Company intends to pursue the restructuring in accordance with the terms set forth in the RSA and the RSA Amendment, there can be no assurance that the Company will be successful in completing a restructuring or any other similar transaction on the terms set forth in the RSA and the RSA Amendment, on different terms or at all.

~~Table of Contents~~

~~Purchase and Sale Agreement~~

On October 20, 2016 (the “Execution Date”), Stone entered into the PSA with Tug Hill. Pursuant to the terms of the PSA, Stone agreed to sell the Properties to Tug Hill (the “Disposition”) for $360 million in cash, subject to customary purchase price adjustments (the “Purchase Price”).

The Disposition has an effective date of June 1, 2016. In connection with the execution of the PSA, Tug Hill deposited $5.0 million in escrow, which amount may be supplemented by an additional $31 million at a later date on certain conditions being met. Upon a closing, the deposit will be credited against the Purchase Price. From the Execution Date through December 19, 2016 (the “Diligence Period”), Tug Hill intends to conduct customary due diligence to assess the aggregate dollar value of any title and environmental defects associated with the Properties. The parties expect to close the Disposition by February 25, 2017, subject to customary closing conditions and approval by the Bankruptcy Court.

The PSA contains customary representations, warranties and covenants. From and after the closing of the Disposition, Stone and Tug Hill, respectively, have agreed to indemnify each other and their respective affiliates against certain losses resulting from any breach of their representations, warranties or covenants contained in the PSA, subject to certain customary limitations and survival periods. Additionally, from and after closing of the Disposition, Stone has agreed to indemnify Tug Hill for certain identified retained liabilities related to the Properties, subject to certain survival periods, and Tug Hill has agreed to indemnify Stone for certain assumed obligations related to the Properties.

The PSA may be terminated, subject to certain exceptions, (i) upon mutual written consent, (ii) if the closing has not occurred by March 1, 2017, (iii) for certain material breaches of representations and warranties or covenants that remain uncured, (iv) if, on or prior to the end of the Diligence Period, title and environmental defect amounts (after application of customary thresholds and deductibles), casualty losses and the value of any assets excluded from the Properties due to the exercise of preferential purchase rights or consents equal or exceed $10 million in the aggregate, (v) if Stone fails to file for bankruptcy on or before December 9, 2016, (vi) if the Bankruptcy Court does not enter an order approving Stone’s assumption of the PSA and certain other matters within 30 days of Stone filing for bankruptcy, (vii) if the Bankruptcy Court does not enter a sale order for the Disposition by February 10, 2017, and (viii) upon the occurrence of certain other events specified in the PSA.

~~Note 17 – Guarantor Financial Statements~~

Stone Offshore is an unconditional guarantor (the "Guarantor Subsidiary") of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents unaudited condensed consolidating financial information as of September 30, 2016 and December 31, 2015 and for the three and nine month periods ended September 30, 2016 and 2015 on an issuer (parent company), Guarantor Subsidiary, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

~~Table of Contents~~

~~CONDENSED CONSOLIDATING BALANCE SHEET~~

~~SEPTEMBER 30, 2016~~

~~(In thousands)~~

Parent
Guarantor
Subsidiary

Non-
Guarantor
Subsidiaries
Eliminations Consolidated
Assets
Current assets:
Cash and cash equivalents $ 152,384
$ 30,015
$ —
$ —
$ 182,399
Accounts receivable 17,336
40,736
883
(14,892 ) 44,063
Fair value of derivative contracts —
6,261
—
—
6,261
Current income tax receivable 19,863
—
—
—
19,863
Other current assets 11,176
—
—
—
11,176
Total current assets 200,759
77,012
883
(14,892 ) 263,762
Oil and gas properties, full cost method:
Proved 1,932,435
7,586,930
45,196
—
9,564,561
Less: accumulated DD&A (1,932,640 ) (7,076,233 ) (45,196 ) —
(9,054,069 )
Net proved oil and gas properties (205 ) 510,697
—
—
510,492
Unevaluated 261,101
143,125
—
—
404,226
Other property and equipment, net 27,227
—
—
—
27,227
Other assets, net 28,852
948
—
—
29,800
Investment in subsidiary 480,971
—
—
(480,971 ) —
Total assets $ 998,705
$ 731,782
$ 883
$ (495,863 )
$ 1,235,507
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors $ 35,189
$ 8,963
$ —
$ (14,893 ) $ 29,259
Undistributed oil and gas proceeds 6,535
904
—
—
7,439
Accrued interest 22,917
—
—
—
22,917
Asset retirement obligations —
60,223
—
—
60,223
Current portion of long-term debt 292,795
—
—
—
292,795
Other current liabilities 10,778
125
—
—
10,903
Total current liabilities 368,214
70,215
—
(14,893 ) 423,536
Long-term debt 1,122,945
—
—
—
1,122,945
Asset retirement obligations 1,336
181,480
—
—
182,816
Other long-term liabilities 25,871
—
—
—
25,871
Total liabilities 1,518,366
251,695
—
(14,893 ) 1,755,168
Commitments and contingencies

Stockholders’ equity:
Common stock 56
—
—
—
56
Treasury stock (860 ) —
—
—
(860 )
Additional paid-in capital 1,657,028
1,344,577
109,079
(1,453,656 ) 1,657,028
Accumulated deficit (2,179,803 ) (868,408 ) (108,196 ) 976,604
(2,179,803 )
Accumulated other comprehensive income 3,918
3,918
—
(3,918 ) 3,918
Total stockholders’ equity (519,661 ) 480,087
883
(480,970 ) (519,661 )
Total liabilities and stockholders’ equity $ 998,705
$ 731,782
$ 883
$ (495,863 ) $ 1,235,507

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~~CONDENSED CONSOLIDATING BALANCE SHEET~~

~~DECEMBER 31, 2015~~

~~(In thousands)~~

Parent
Guarantor
Subsidiary

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

~~Table of Contents~~

~~CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS~~

~~THREE MONTHS ENDED SEPTEMBER 30, 2016~~

~~(In thousands)~~

Parent Guarantor
Subsidiary Non-
Guarantor
Subsidiaries Eliminations Consolidated
Operating revenue:
Oil production $ 3,587
$ 67,529
$ —
$ —
$ 71,116
Natural gas production 7,216
8,385
—
—
15,601
Natural gas liquids production 5,737
929
—
—
6,666
Other operational income 1,044
—
—
—
1,044
Total operating revenue 17,584
76,843
—
—
94,427
Operating expenses:
Lease operating expenses 2,771
14,205
—
—
16,976
Transportation, processing and gathering expenses 9,607
1,026
—
—
10,633
Production taxes 669
166
—
—
835
Depreciation, depletion and amortization 26,388
32,530
—
—
58,918
Write-down of oil and gas properties 1
36,483
—
—
36,484
Accretion expense 58
10,024
—
—
10,082
Salaries, general and administrative expenses 15,425
—
—
—
15,425
Incentive compensation expense 2,160
—
—
—
2,160
Restructuring fees 5,784
—
—
—
5,784
Other operational expenses 9,214
(155 ) —
—
9,059
Derivative expense, net —
199
—
—
199
Total operating expenses 72,077
94,478
—
—
166,555
Loss from operations (54,493 ) (17,635 ) —
—
(72,128 )
Other (income) expenses:
Interest expense 16,924
—
—
—
16,924
Interest income (43 ) (15 ) —
—
(58 )
Other income (64 ) (208 ) —
—
(272 )
Other expense 16
—
—
—
16
Loss from investment in subsidiaries 19,300
—
1
(19,301 ) —
Total other (income) expenses 36,133
(223 ) 1
(19,301 ) 16,610
Loss before taxes (90,626 ) (17,412 ) (1 ) 19,301
(88,738 )
Provision (benefit) for income taxes:
Current (991 ) —
—
—
(991 )
Deferred —
1,888
—
—
1,888
Total income taxes (991 ) 1,888
—
—
897
Net loss $ (89,635 ) $ (19,300 ) $ (1 ) $ 19,301
$ (89,635 )
Comprehensive loss $ (93,102 ) $ (19,300 ) $ (1 ) $ 19,301
$ (93,102 )

~~Table of Contents~~

~~CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS~~

~~THREE MONTHS ENDED SEPTEMBER 30, 2015~~

~~(In thousands)~~

Parent
Guarantor
Subsidiary

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

~~Table of Contents~~

~~CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2016~~

~~(In thousands)~~

Parent Guarantor
Subsidiary Non-
Guarantor
Subsidiaries Eliminations Consolidated
Operating revenue:
Oil production $ 4,971
$ 199,131
$ —
$ —
$ 204,102
Natural gas production 13,642
29,685
—
—
43,327
Natural gas liquids production 9,246
5,873
—
—
15,119
Other operational income 1,737
—
—
—
1,737
Total operating revenue 29,596
234,689
—
—
264,285
Operating expenses:
Lease operating expenses 9,313
46,023
13
—
55,349
Transportation, processing and gathering expenses 17,174
1,483
—
—
18,657
Production taxes 1,311
583
—
—
1,894
Depreciation, depletion and amortization 45,452
121,255
—
—
166,707
Write-down of oil and gas properties 15,859
268,128
350
—
284,337
Accretion expense 174
29,973
—
—
30,147
Salaries, general and administrative expenses 48,392
(199 ) —
—
48,193
Incentive compensation expense 11,809
—
—
—
11,809
Restructuring fees 16,173
—
—
—
16,173
Other operational expenses 43,059
125
6,082
—
49,266
Derivative expense, net —
687
—
—
687
Total operating expenses 208,716
468,058
6,445
—
683,219
Loss from operations (179,120 ) (233,369 ) (6,445 ) —
(418,934 )
Other (income) expenses:
Interest expense 49,764
—
—
—
49,764
Interest income (459 ) (15 ) —
—
(474 )
Other income (123 ) (717 ) —
—
(840 )
Other expense 27
—
—
—
27
Loss from investment in subsidiaries 250,029
—
6,445
(256,474 ) —
Total other (income) expenses 299,238
(732 ) 6,445
(256,474 ) 48,477
Loss before taxes (478,358 ) (232,637 ) (12,890 ) 256,474
(467,411 )
Provision (benefit) for income taxes:
Current (4,178 ) —
—
—
(4,178 )
Deferred —
10,947
—
—
10,947
Total income taxes (4,178 ) 10,947
—
—
6,769
Net loss $ (474,180 ) $ (243,584 ) $ (12,890 ) $ 256,474
$ (474,180 )
Comprehensive loss $ (488,214 ) $ (243,584 ) $ (12,890 ) $ 256,474
$ (488,214 )

~~Table of Contents~~

~~CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2015~~

~~(In thousands)~~

Parent
Guarantor
Subsidiary

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

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~~CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2016~~

~~(In thousands)~~

Parent
Guarantor
Subsidiary

Non-Guarantor
Subsidiaries
Eliminations Consolidated
Cash flows from operating activities:
Net loss $ (474,180 ) $ (243,584 ) $ (12,890 ) $ 256,474
$ (474,180 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization 45,452
121,255
—
—
166,707
Write-down of oil and gas properties 15,859
268,128
350
—
284,337
Accretion expense 174
29,973
—
—
30,147
Deferred income tax provision —
10,947
—
—
10,947
Settlement of asset retirement obligations (78 ) (14,129 ) (899 ) —
(15,106 )
Non-cash stock compensation expense 6,407
—
—
—
6,407
Non-cash derivative expense —
1,261
—
—
1,261
Non-cash interest expense 14,278
—
—
—
14,278
Other non-cash expense —
—
6,081
—
6,081
Change in current income taxes 21,584
—
—
—
21,584
Non-cash loss from investment in subsidiaries 250,029
—
6,445
(256,474 ) —
Change in intercompany receivables/payables (1,658 ) 1,658
—
—
—
(Increase) decrease in accounts receivable 7,966
(3,116 ) (882 ) —
3,968
(Increase) decrease in other current assets (4,459 ) —
33
—
(4,426 )
Increase (decrease) in accounts payable 7,385
(4,168 ) —
—
3,217
Decrease in other current liabilities (13,924 ) (298 ) —
—
(14,222 )
Other (7,389 ) (718 ) —
—
(8,107 )
Net cash (used in) provided by operating activities (132,554 ) 167,209
(1,762 ) —
32,893
Cash flows from investing activities:
Investment in oil and gas properties (63,075 ) (137,196 ) (351 ) —
(200,622 )
Investment in fixed and other assets (1,231 ) —
—
—
(1,231 )
Change in restricted funds —
—
1,046
—
1,046
Investment in subsidiaries —
—
716
(716 ) —
Net cash (used in) provided by investing activities (64,306 ) (137,196 ) 1,411
(716 ) (200,807 )
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 (285 ) —
—
—
(285 )
Deferred financing costs (900 ) —
—
—
(900 )
Equity proceeds from parent —
—
(716 ) 716
—
Net payments for share-based compensation (752 ) —
—
—
(752 )
Net cash provided by (used in) financing activities 339,563
—
(716 )
716

339,563
Effect of exchange rate changes on cash —
—
(9 ) —
(9 )
Net change in cash and cash equivalents 142,703
30,013
(1,076 ) —
171,640
Cash and cash equivalents, beginning of period 9,681
2
1,076
—
10,759
Cash and cash equivalents, end of period $ 152,384
$ 30,015
$ —
$ —
$ 182,399

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~~CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2015~~

~~(In thousands)~~

Parent
Guarantor
Subsidiary

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

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~~Item~~ITEM 2. ~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this ~~“Form 10-Q”~~"Form 10-Q") includes ~~“forward-looking statements”~~"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”~~"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~~2016 Annual Report on Form 10-K and in this Form 10-Q.

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

expected results from risk-weighted drilling success;

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

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

our outlook on oil and natural gas prices;

estimates of our oil and natural gas reserves;

any estimates of future earnings growth;

the impact of political and regulatory developments;

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

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

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

the outcome of restructuring efforts and asset sales;

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

any expected results or benefits associated with our acquisitions;

our access to capital and our anticipated liquidity;

estimates of future income taxes; and

our business strategy and other plans and objectives for future ~~operations.~~operations, including the board's assessment of the Company's strategic direction.

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

~~our ability to consummate the sale of the Properties (defined below) as contemplated by the PSA (defined below);~~

~~our ability to confirm and consummate a plan of reorganization in accordance with the terms of the RSA and the RSA Amendment (defined below), or alternative restructuring transaction;~~

~~risks attendant to the bankruptcy process, including the effects thereof on the Company’s business and on the interests of various constituents;~~

~~the length of time that the Company might be required to operate in bankruptcy and the continued availability of operating capital during the pendency of such proceedings;~~

~~risks associated with third party motions in any bankruptcy case, which may interfere with the ability to confirm and consummate a plan of reorganization;~~

~~potential adverse effects of bankruptcy proceedings on the Company’s liquidity or results of operations;~~

~~increased costs to execute a reorganization;~~

~~effects of bankruptcy proceedings on the market price on the Company’s common stock and on the Company’s ability to access the capital markets;~~

~~our ability to maintain our listing on the New York Stock Exchange ("NYSE");~~

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 and compliance with debt ~~covenants and our ability to continue as a going concern;~~covenants;

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

~~our ability~~the potential need to ~~continue to borrow under our credit facility;~~sell certain assets or raise additional capital;

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

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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;

third-party interruption of sales to market;

inflation;

lack of availability and cost of goods and services;

market conditions relating to potential acquisition and divestiture transactions;

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

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

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

competition in the oil and gas industry;

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our inability to retain and attract key personnel;

drilling and other operating risks, including the consequences of a catastrophic event;

unsuccessful exploration and development drilling activities;

hurricanes and other weather conditions;

availability, cost and adequacy of insurance coverage;

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

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

other risks described in this Form ~~10-Q.~~10-Q and our 2016 Annual Report on Form 10-K.

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~~2016 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our ~~2015~~2016 Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“("MD~~&A”~~&A") contained in this Form 10-Q should be read in conjunction with the MD&A contained in our ~~2015~~2016 Annual Report on Form 10-K.

Critical Accounting Policies and Estimates

Our ~~2015~~2016 Annual Report on Form 10-K describes the accounting estimates that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments. Our most significant estimates are:

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

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

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

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

effectiveness and estimated fair value of derivative positions;

classification of unevaluated property costs;

capitalized general and administrative costs and interest;

estimates of fair value in business combinations;

estimates of reorganization value and enterprise value;

fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting;

current and deferred income taxes; and

contingencies.

This Form 10-Q should be read together with the discussion contained in our ~~2015~~2016 Annual Report on Form 10-K regarding these critical accounting policies. There have been no material changes to our critical accounting policies from those described in our 2016 Annual Report on Form 10-K, except as described below.

Fresh Start Accounting

Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, "Reorganizations" as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. The new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

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Derivative Instruments and Hedging Activities

Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, they were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017 and 2018 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, the net changes in the mark-to-market valuations and the monthly settlements on these derivative contracts will be recorded in earnings through derivative income (expense).

Other Factors Affecting Our Business and Financial Results

In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our ~~2015~~2016 Annual Report on Form 10-K and in this Form 10-Q under Part II, Item 1A. Risk Factors, regarding our known material risk factors.

Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We ~~have~~ leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. ~~On October 20,~~At December 31, 2016, we ~~entered into~~had producing properties and acreage in the Marcellus and Utica Shales in Appalachia. In connection with our restructuring efforts, we determined that a ~~purchase~~sale of the Appalachia Properties would be a beneficial way to maximize value for all stakeholders. We completed the sale of the Appalachia Properties to EQT on February 27, 2017 for net consideration of approximately $522.5 million. See "Reorganization and Emergence from Voluntary Chapter 11 Proceedings" below for additional information on the sale ~~agreement to sell all~~ of ~~our Appalachian properties. See “Restructuring Support Agreement”~~ ~~and “Purchase and Sale Agreement”~~ ~~below.~~the Appalachia Properties.

~~We experienced significant declines~~As discussed in ~~oil, natural gas and NGL prices during~~Note 3 – Fresh Start Accounting, upon emergence from bankruptcy, the ~~second half~~Company adopted fresh start accounting in accordance with the provisions of ~~2014, with lower prices continuing throughout 2015 and into 2016,~~ASC 852, "Reorganizations", which resulted in ~~reduced revenue and cash flows and caused us~~the Company becoming a new entity for financial reporting purposes on the Effective Date. As a result of the adoption of fresh start accounting, the Company’s unaudited condensed consolidated financial statements subsequent 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 theyFebruary 28, 2017 will not be comparable to its financial statements prior to that date. References to "Successor" or "Successor Company" relate to ~~our ability to comply with~~ the ~~covenants in the agreements governing our indebtedness. As~~financial position and results of November 7, 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 $11.4 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~~operations of the ~~undrawn amount on our $500 million borrowing base. On April 13, 2016,~~reorganized Company subsequent to February 28, 2017. References to "Predecessor" or "Predecessor Company" relate to 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~~financial position and results 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 executionoperations 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.~~Company prior to, and including, February 28, 2017.

Reorganization and Emergence from Voluntary Chapter 11 Proceedings

~~As of September 30,~~On December 14, 2016, we ~~were in compliance with all covenants~~filed Bankruptcy Petitions seeking relief 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 quarterprovisions 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 endChapter 11 of the ~~first quarter~~Bankruptcy Code to pursue a prepackaged plan of reorganization to address our liquidity and capital structure. On February 15, 2017, ~~when~~ the ~~relaxed covenant levels end, unless a material portion of our debt is repaid, reduced or exchanged into equity. See~~ ~~"Liquidity~~Bankruptcy Court entered an order confirming the Plan, and ~~Capital Resources"~~.on February 28, 2017, the Plan became effective and we emerged from bankruptcy.

In ~~late June 2016,~~connection with our restructuring efforts, we ~~terminated~~sold our ~~deep water drilling rig contract with Ensco~~Appalachia Properties to EQT on February 27, 2017, for ~~total~~net consideration of ~~$20 million. Additionally,~~approximately $522.5 million, representing gross proceeds of $527.0 million adjusted downward by approximately $4.5 million for purchase price adjustments for operations related to the Appalachia Properties after June 1, 2016, the effective date of the transaction. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company's cash payment obligations under the Plan. At December 31, 2016, the Appalachia Properties accounted for approximately 34% of the Predecessor Company’s total estimated proved oil and natural gas reserves on a volume equivalent basis. Upon closing of the sale on February 27, 2017, we no longer have operations or assets in ~~late June 2016, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, allowing us to resume production at the Mary field. See~~ ~~"Liquidity and Capital Resources". In August 2016, we paid $7.5 million for the early terminations of an Appalachian drilling rig contract and a contract with an offshore vessel provider.~~Appalachia.

~~In April 2016, production~~Upon emergence from our deep water Amethyst well was shut in to allow for a technical evaluation. During the first week of November, we initiated acid stimulation work and are intermittently flowing the well while we continue to observe and evaluate the well’s performance. We have identified potential factors which may explain the reason for the April 2016 pressure decline and ultimate production shut in. If the well continues to perform, we expect to flow and evaluate the well for an extended period of time at 10-15 MMcf per day, although the gas export pipeline capacity may be temporarily restricted due to a gas plant outage that occurred in late June 2016 as a result of an explosion at the facility. Unsuccessful intervention operations may result in reductionsbankruptcy, pursuant to the ~~well's estimated proved reserve quantities and estimated future net cash flows, which could negatively affect our borrowing base under our credit facility. As~~terms of ~~December 31, 2015, Amethyst represented approximately 23% and 26% of our estimated proved reserves quantities and standardized measure of discounted future net cash flows, respectively.~~ the Plan, the following significant transactions occurred:

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~~Restructuring Support Agreement~~

~~On October 20, 2016,~~The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the ~~Company entered into a restructuring support agreement (the "RSA") with~~consummation of certain ~~holders of~~business combinations or sale transactions involving the 2017 Convertible Notes and certain holders of the 2022 Notes (together with the 2017 Convertible Notes, the “Notes” and the holders thereof, the “Noteholders”) to support a restructuring on the terms of a pre-packaged plan of reorganization (the “Plan”). The RSA contemplates that the Company will file for voluntary relief under chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in a United States Bankruptcy Court (the “Bankruptcy Court”) on or before December 9, 2016 to implement the Plan in accordance with the term sheet annexed to the RSA (the “Term Sheet”).Company.

The ~~RSA would become effective upon (i) execution by~~Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated as the Company and Noteholders holding, in the aggregate, at least two-thirds of the outstanding aggregate principal amount of the Notes, and (ii) Stone having entered into a PSA for the sale of Properties, defined below, for a cash purchase price of at least $350 million. Both conditions were satisfied, with Noteholders holding approximately 85.4% of the aggregate principal amount of the Notes executing the RSA and Stone signing the PSA, as indicated below. PursuantAmended Credit Agreement. The obligations owed to the ~~terms of the RSA and the Term Sheet, Noteholders and other interest holders will receive treatment~~lenders under the ~~Plan summarized as follows:~~

~~The Noteholders will receive their pro rata share of (a) $150 million of~~Pre-Emergence Credit Agreement were converted to obligations under the net cash proceeds from the sale of Stone’s approximately 86,000 net acres in the Appalachia regions of Pennsylvania and West Virginia (the “Properties”) plus 85% of the net cash proceeds from the sale of the Properties in excess of $350 million, if any, (b) 95% of the common stock in reorganized Stone and (c) $225 million of new 7.5% second lien notes due 2022.

All claims of creditors with unsecured claims, other than the claims by the ~~Noteholders,~~holders of the 2022 Notes and 2017 Convertible Notes, including vendors, ~~shall be~~were unaltered and ~~will be~~ paid in full in the ordinary course of business to the extent ~~such~~the claims ~~are~~were undisputed. ~~Stone estimates that such unsecured claims are in~~

For further information regarding the ~~range~~debt instruments of ~~approximately $17 million to $27 million in~~ the ~~aggregate.~~Successor Company, see Liquidity and Capital Resources below.

~~Holders~~Management Changes

On April 25, 2017, David H. Welch informed the board of ~~claims arising on account~~directors of Stone’s existing revolving credit facility will receive (a)(i) if such holders vote, as a class, to accept the Plan, commitments on terms set forth on Exhibit 1(a) to the Term Sheet, on a pro rata basis, under an amended revolving credit facility, or (ii) if such holders, as a class, do not vote to accept the Plan (or are deemed to reject the Plan), a term loan on terms set forth on Exhibit 1(b) to the Term Sheet, or (b) such other treatment as is acceptable to the Company of his intention to retire as the Chief Executive Officer and ~~the Noteholders and consistent with the Bankruptcy Code, including, but not limited to, section 1129(b) of the Bankruptcy Code.~~

~~Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan.~~

~~The RSA contains certain covenants on the part~~President of the Company and ~~the Noteholders who are signatories to the RSA, including that such Noteholders will vote in favor~~as a member of the ~~Plan, support~~board. Effective April 28, 2017, the ~~sale~~board of directors elected James M. Trimble, a member of the ~~Properties and otherwise facilitate the restructuring transaction, in each case subject~~board, to ~~certain terms and conditions in the RSA. The consummation of the Plan will be subject to customary conditions and other requirements, as well~~serve as the ~~sale by Stone~~Company's Interim Chief Executive Officer and President, and appointed Keith A. Seilhan, the Company's Senior Vice President – Gulf of Mexico, to serve as the Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court. The RSA also provides for termination by each party, or by either party, upon the occurrence of certain events, including without limitation, termination by the Noteholders upon the failure of the Company to achieve certain milestones set forth in Schedule 1 to the RSA.

~~On November 4, 2016 the Company and the Noteholders entered into an amendment to the RSA (the “RSA Amendment”) pursuant to which:~~

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~~Solicitation of noteholders in support of the Plan will commence by November 10, 2016.~~

~~Purchase and Sale Agreement~~

On October 20, 2016 (the “Execution Date”), Stone entered into a purchase and sale agreement (the “PSA”) with TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”). Pursuant to the terms of the PSA, Stone agreed to sell the Properties to Tug Hill (the “Disposition”) for $360 million in cash, subject to customary purchase price adjustments (the “Purchase Price”).

Upon closing of the Disposition, Stone will no longer have operations or assets in Appalachia. Our Appalachian properties accounted for approximately 1% of our estimated proved oil, natural gas and NGL reserves at December 31, 2015. During 2015, virtually all of our Appalachian reserves were removed from proved reserves due to the effect of reduced Appalachian reserve prices for natural gas and NGLs. Our operating margins in Appalachia remained at relatively low levels during 2015 and through June 2016 as a result of low commodity prices and high midstream costs in the area.

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Company's Chief Operating Officer.

Known Trends and Uncertainties

~~Declining Commodity Prices~~Non-designation of commodity derivatives– With respect to our 2017 and 2018 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges for accounting purposes. Accordingly, these derivative instruments are accounted for on a mark-to-market basis with changes in fair value recognized currently in earnings through derivative income (expense) in the statement of operations. As a result of these mark-to-market adjustments, we will likely experience volatility in earnings from time to time due to commodity price volatility. See Results of Operations below for more information.

Oil and Gas Properties Full Cost Ceiling Test – 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 nine months ended September 30, 2016, we recognized ceiling test write-downs of our oil and gas properties of $351 million, $1,362 million and $284 million, respectively. If NYMEX commodity prices remain at current levels (approximately ~~$46.67~~$47.50 per Bbl of oil and ~~$2.785~~$3.20 per MMBtu of natural gas), we would expect an increase in the ~~12-month~~twelve-month average price used in estimating the present value of estimated future net cash flows of our proved reserves. Accordingly, we would not expect downward revisions to our estimated proved reserve quantities as a result of pricing that would cause us to recognize ~~an additional~~a ceiling test write-down in the ~~fourth~~second quarter of ~~2016.~~2017. However, significant evaluations or impairments of unevaluated costs or other well ~~performance-related revisions~~performance related activities affecting proved reserve quantities could cause us to recognize such a write-down.

~~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 ended 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 September 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.

Additionally, the significant decline in commodity prices has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. The borrowing base under our bank credit facility as of November 7, 2016 was $360 million, a reduction from the borrowing base of $500 million as of April 12, 2016. See ~~"Liquidity and Capital Resources"~~. Continued low commodity prices or further declines in commodity prices could have a further adverse impact on the estimated value and quantities of our proved reserves and could result in additional reductions of our borrowing base under our bank credit facility.

BOEM Financial Assurance Requirements – ~~The Bureau of Ocean Energy Management ("BOEM")~~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 intowards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately ~~$139~~$118 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~~A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to ~~BOEM and are awaiting its review and approval.~~reflect the updated decommissioning estimates.

~~Additionally, on~~In July ~~14,~~ 2016, BOEM issued a new NTL, with an effective date of September 12, 2016, 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.~~lessees. The NTL ~~effective September 12, 2016, does away with~~discontinues the ~~agency's past practice~~policy of ~~waiving supplemental bonding obligations~~Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company ~~could~~can 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 also provides new procedures for how BOEM determines a lessee’s decommissioning ~~obligations and, consistent with those procedures, BOEM has tentatively proposed an implementation timeline~~obligations.

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that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) “Self-Insurance” letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) “Proposal” letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) “Order” letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a “tailored plan” for posting additional security over a phased-in period of time, (B) within 60 days of such letter, provide additional security for “sole liability” properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan). BOEM tentatively expects to approve or deny tailored plans submitted by lessees on or around September 11, 2017, although extensions may be granted to companies actively working with BOEM to finalize tailored plans. We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are not eligible to self-insure any of our additional security obligations. We received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security ~~will~~may be required, and we ~~intend~~are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of BSEE's. The September 30, 2016 Self-Insurance determination letter was rescinded by BOEM on March 24, 2017. In the ~~provision~~first quarter of ~~new financial assurances required to be posted as a result of~~2017, BOEM announced that it will extend the implementation timeline for the new ~~NTL. Our~~NTL by an additional six months. The revised proposed plan ~~would~~we submitted to BOEM may require ~~approximately $35~~potentially $30 million to ~~$40~~$60 million of incremental financial assurance or bonding for ~~2016 through~~non-sole liability properties by the end of 2017 ~~a portion of which may require cash collateral.~~or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL. Under the revised proposed plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by ~~BOEM.~~BOEM, and BOEM may

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require further revisions to our plan. Additionally, it is uncertain at this time what impact the new Trump administration may have on the current financial regulatory framework. 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 our 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.

~~The~~In addition, if fully implemented, 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~~Outer Continental Shelf ("OCS"), which will in turn force these operators to seek additional surety bonds and could, consequently, ~~exceed~~challenge 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 companies 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 recently provided some cash collateral on a portion of our existing surety bonds and may be required to provide additional cash collateral on existing and new surety bonds we expect BOEM will require to satisfy their financial assurance requirements.HurricanesWe 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 infrom a concentrated area of 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.~~Amended Credit Agreement.

Deep Water Operations– We are currently operating two significant properties in the deep water of the GOM and engage in deep water drilling operations. Operations in the deep water involve high operational risks. Despite technological advances over the last several years, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant losses on our statement of operations as well as going concern issues.

Liquidity and Capital Resources

~~Overview.~~Overview

In connection with our restructuring efforts, we sold our Appalachia Properties on February 27, 2017 for net consideration of approximately $522.5 million. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company's cash payment obligations under the Plan. Upon emergence from bankruptcy on February 28, 2017, we eliminated approximately $1.1 billion in principal amount of debt. For additional details, see "Reorganization and Emergence from Voluntary Chapter 11 Proceedings" above. These significant transactions improved our financial position and liquidity.

As of ~~November 7, 2016, the Company’s cash and cash equivalents totaled approximately $181.5million, and the Company~~May 8, 2017, we had approximately ~~$1,428~~$175.6 million of cash on hand and $72.3 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the terms of the Amended Credit Agreement, and approximately $236 million in total debt outstanding, including ~~$300 million of 2017 Convertible Notes, $775~~$225 million of 2022 Second Lien Notes ~~$341.5~~and $11 million outstanding under ~~our bank credit facility and $11.4 million outstanding under our~~the Building Loan.

~~On April 13, 2016, the borrowing base under our bank credit facility was reduced from $500 million to $300 million. On that date, we~~ We had ~~$457 million of~~no outstanding borrowings and ~~$18.3~~approximately $12.5 million of outstanding letters of credit under the ~~bank credit facility,~~Amended Credit Agreement at May 8, 2017, 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

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~~facility in conformity with the borrowing base limitation. See "Bank Credit Facility"~~ ~~below. As of November 7, 2016, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving approximately $6.0~~$137.5 million of availability under the ~~bank credit facility.~~Amended Credit Agreement. Our initial borrowing base under the Amended Credit Agreement has been set at $200.0 million with available borrowings thereunder of up to $150.0 million until the first borrowing base redetermination in November 2017. There are no assurances that the borrowing base will remain at the current level, and there could potentially be a decrease in the borrowing base at redetermination.

We have $300 million of 2017 Convertible Notes that we need to restructure or repay by March 1, 2017. Additionally, we have an interest obligation under our 2022 Notes of approximately $29.2 million due on November 15, 2016 (see "~~Senior Notes"~~ ~~below). As a result of continued decreases in commodity prices~~established and the level of our indebtedness, we continue to work with financial and legal advisors to analyze various financial, transactional and strategic alternatives. On October 20, 2016, we entered into the RSA with the Noteholders to support a restructuring on the terms of the Plan. The RSA contemplates that we will file for voluntary relief under chapter 11 of the Bankruptcy Code on or before December 9, 2106. See "~~Overview –Restructuring Support Agreement~~". Additionally, on October 20, 2016, we entered into a purchase and sale agreement to sell all of our Appalachia properties for $360 million in cash, subject to customary purchase price adjustments. See "~~Overview~~–~~Purchase and Sale Agreement". We cannot provide any assurances that we will be able to complete a restructuring or asset sales on satisfactory terms to provide liquidity to restructure or pay down our senior indebtedness.~~

~~Our capital expenditure budget for 2016 was set by~~ the board of directors ~~at $200~~of the Company has approved an initial capital expenditures budget for 2017 of $181 million. The capital expenditures budget includes approximately $27 million for exploration opportunities, $54 million for development activities 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 were expected to range between $40$100 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~~plugging and abandonment 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,idle wells 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. In addition, during the third quarter of 2016 we terminated an offshore vessel contract and Appalachian rig contract. The updated rig schedule and cost reduction efforts have decreased our projected 2016 capital expenditures to approximately$160 million to $170 million. 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. As noted above, the rig stacking, subsidy and termination charges were accounted for in other operational expenses and are expected to be approximately $46 million for 2016.

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 was 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 90 MMcfe per day during the third quarter of 2016, with total Appalachia volumes averaging 112 MMcfe per day during the third quarter of 2016. We expect daily production rates from Appalachia to average 120 MMcfe to 140 MMcfe per day in the fourth quarter of 2016. On October 20, 2016, we entered into a purchase and sale agreement to sell all of our Appalachia properties. See "~~Overview~~–~~Purchase and Sale Agreement~~".

platforms. Based on our current outlook of commodity prices and our estimated production for ~~2016,~~2017, 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. Although our capital expenditure budget for 2017 has not yet been approved and is dependent on the outcome of potential chapter 11 proceedings and the related reorganization of the Company, we currently expect to reinstate drilling operations at Pompano in early 2017. While management believes the Company's expectedthat cash flows from operating activities, ~~and~~ cash on hand ~~for 2017~~and availability under the Amended Credit Agreement will be adequate to meet the current 2017 operating and capital expenditure needs of the ~~post-reorganized~~Company.

In April 2017, our board of directors retained financial advisers to assist the board in its determination of the Company's strategic direction, including assessing its various strategic alternatives. The Board is exploring all potential avenues to increase stockholder value, which may include the acquisition of additional assets, accessing external capital, a business combination, or another strategic transaction. No decision has been made with regard to any alternatives, and there can be no assurance that this assessment will result in any transaction.

The Company ~~there are no assurances that a chapter 11 plan will be approved by~~is currently evaluating various acquisition opportunities, which, if successful, would increase the ~~Bankruptcy Court.~~

~~Historically,~~capital requirements of the Company for 2017. Although we have ~~been able~~no current plans to ~~obtain an exemption from supplemental bonding requirements on our offshore leases~~access the public or private equity or debt markets for ~~abandonment obligations based on financial net worth, however, on~~purposes of capital, we may consider such funding sources to provide additional capital if needed.

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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~~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 intowards finalizing and implementing our long-term tailored plan. ~~We have submitted~~A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to ~~BOEM and are awaiting its review and approval.~~reflect the updated decommissioning estimates.

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Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of ~~waiving supplemental bonding obligations~~a company’s tangible net worth, where a company ~~could~~can 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. We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are not eligible to self-insure any of our additional security obligations. We received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security ~~will~~may be required, and we ~~intend~~are continuing to work with BOEM to adjust our previously submitted tailored plan for ~~the provision~~variances between our decommissioning estimates and that of ~~new financial assurances required to be posted as a result of the new NTL. Our~~BSEE's. The September 30, 2016 Self-Insurance determination letter was rescinded by BOEM on March 24, 2017. The revised proposed plan ~~would~~we submitted to BOEM may require ~~approximately $35~~potentially $30 million to ~~$40~~$60 million of incremental financial assurance or bonding for ~~2016 through~~non-sole liability properties by the end of 2017 ~~a portion of which may require cash collateral. Under~~or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the ~~revised plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM.~~NTL.

Although the surety companies have not historically required collateral from us to back our surety bonds, we ~~recently~~have provided some cash collateral on aan immaterial portion of our existing surety bonds and may be required to provide additional cash collateral on existing ~~and~~and/or new surety bonds ~~we expect~~required by BOEM ~~will require~~ to satisfy ~~their~~ financial assurance requirements. This need to obtain additional surety bonds or some other form of financial assurance, could impact our liquidity. See Known Trends and Uncertainties.

~~Indebtedness.~~Indebtedness

Successor Bank Credit Facility – On ~~June 24, 2014, we entered into~~the Effective Date, pursuant to the terms of the Plan, the Predecessor Company's Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement, and the obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement. The Amended Credit Agreement provides for a $200.0 million reserve-based revolving credit facility ~~with commitments totaling $900 million (subject to~~and matures on February 28, 2021.

The Company’s initial borrowing base ~~limitations) through a syndicated bank group, replacing our previous facility.~~under the Amended Credit Agreement has been set at $200.0 million with available borrowings thereunder of up to $150.0 million until the first borrowing base redetermination in November 2017. Interest on loans under the Amended Credit Agreement is calculated using the LIBOR or the base rate, at the election of the Company, plus, in each case, an applicable margin. The ~~bank~~applicable margin is determined based on borrowing base utilization and ranges from 2.00% to 3.00% per annum for base rate loans and 3.00% to 4.00% per annum for LIBOR loans. At March 31, 2017, the Company had no outstanding borrowings and approximately $12.5 million of outstanding letters of credit, ~~facility matures on July 1, 2019 and is guaranteed by our Guarantor Subsidiaries.~~ leaving $137.5 million of availability under the Amended Credit Agreement.

The borrowing base under the ~~bank credit facility~~Amended Credit Agreement 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~~loans, with the first borrowing base redetermination to occur in November 2017. Subject to certain exceptions, the Amended Credit Agreement is required to be guaranteed by all of the material domestic direct and indirect subsidiaries of the Company. As of March 31, 2017, the Amended Credit Agreement is guaranteed by Stone Offshore. The Amended Credit Agreement is secured by substantially all of the Company’s and its subsidiaries’ assets.

The Amended Credit Agreement provides for customary optional and mandatory prepayments, affirmative and negative covenants and events of default, including limitation on the incurrence of debt, liens, restrictive agreements, mergers, asset sales, dividends, investments, affiliate transactions and restrictions on commodity hedging. During the continuance of an event of default, the lenders ~~each have discretion at any time, but~~may take a number of actions, including declaring the entire amount then outstanding under the Amended Credit Agreement due and payable. The Amended Credit Agreement also requires maintenance of certain financial covenants, including (i) a consolidated funded debt to EBITDA ratio of not more than ~~two additional times in any calendar year,~~2.75x for the test period ending March 31, 2017, 2.50x for the test period ending June 30, 2017, 3.00x for the test period ending September 30, 2017, 2.75x for the test period ending December 31, 2017, 2.50x for the test periods ending March 31, 2018, June 30, 2018, September 30, 2018 and December 31, 2018, respectively, 2.75x for the test period ending March 31, 2019, 3.00x for the test period ending June 30, 2019, 3.50x for the test periods ending September 30, 2019 and December 31, 2019, respectively, 3.00x for the test period ending March 31, 2020, 2.75x for the test periods ending June 30, 2020 and September 30, 2020, respectively, and 2.50x for the test periods ending December 31, 2020 and March 31, 2021, respectively, (ii) a consolidated interest coverage ratio of not less than 2.75 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~~1.00, and (iii) a requirement to ~~$300 million. On that date, we had $457 million~~maintain minimum liquidity 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~~at least 20% 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 ended 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 definedbase. We were 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 incompliance with 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 borrowingscovenants under the ~~credit facility, bringing total borrowings and letters~~Amended Credit Agreement as of ~~credit outstanding under~~March 31, 2017.

2022 Second Lien Notes – On the bank credit facility in conformity with the borrowing base limitation. On November 7, 2016, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving $6.0 million of availability under the bank credit facility.

We have been engaged in discussions and have exchanged proposals with the lenders under our bank credit facility with respect to the treatment of the bank credit facility in a chapter 11 proceeding and a related amendment to the bank credit facility; however, no agreement has been reached. While we expect to continue discussions and related negotiations with the lenders under our bank credit facility, there can be no assurance that an agreement will be reached. PursuantEffective Date, pursuant to the terms of the ~~RSA, if~~Plan, the ~~lenders under our bank credit facility do not vote to accept the Plan (or are deemed to reject the Plan), they will receive, on a pro rata basis, a $342~~Successor Company issued $225.0 million ~~exit term loan or such other treatment as is acceptable to Stone and the Noteholders and consistent with the Bankruptcy Code. The exit term loan would have a five year maturity from the effective date~~ of the RSA and would be a first-lien senior secured obligation guaranteed by Stone Offshore, not subject to a borrowing base, to be repaid at any time at par at the election of Stone. The exit term loan would bear interest at the Treasury rate plus 2.00% per annum.

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 impactCompany’s 2022 Second Lien Notes. Interest on the ~~value~~2022 Second Lien Notes will accrue at a rate of ~~our estimated proved reserves~~7.50% per annum payable semi-annually in arrears on May 31 and November 30 of each year in ~~turn, the~~cash, beginning November 30, 2017. The 2022 Second Lien Notes

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~~market value used~~are secured on a second lien priority basis by the ~~lenders~~same collateral that secures the Amended Credit Agreement, including the Company’s oil and natural gas properties, and are guaranteed by the Guarantor. The 2022 Second Lien Notes mature on May 31, 2022. Pursuant to ~~determine our borrowing base. Continued low commodity prices or further declines~~the terms of the Intercreditor Agreement, the security interest in ~~commodity prices~~those assets that secure the 2022 Second Lien Notes and the related guarantee will ~~likely have a further material adverse impact on~~be contractually subordinated to liens thereon that secure the Company’s Amended Credit Agreement and certain other permitted obligations as set forth in the 2022 Second Lien Notes Indenture. Consequently, the 2022 Second Lien Notes and the related guarantee will be effectively subordinated to the Amended Credit Agreement and such other permitted secured indebtedness to the extent of the value of ~~our estimated proved reserves.~~such assets.

~~Interest~~At any time prior to May 31, 2020, the Company may, at its option, on ~~loans under the bank credit facility is calculated using the LIBOR rate~~any one 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%~~more occasions redeem up 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 September 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 end35% 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 have an interest payment obligation under our 2022 Notes of approximately $29.2 million, due on November 15, 2016. The indenture governing the 2022 Notes provides a 30-day grace period that extends the latest date for making this cash interest payment to December 15, 2016 before an Event of Default occurs under the indenture, which would give the trustee or the holders of at least 25% inaggregate principal amount of the 2022 Second Lien Notes issued under the ~~option to accelerate payment~~2022 Second Lien Notes Indenture at a redemption price of 107.5% of the principal amount of the 2022 Second Lien Notes, plus accrued and unpaid interest onto the redemption date, with an amount of cash equal to the net cash proceeds of certain equity offerings; provided that at least 65% of the aggregate principal amount of the 2022 ~~Notes.~~Second Lien Notes remains outstanding after each such redemption. On ~~October 20, 2016, we entered into~~or after May 31, 2020, the ~~RSA with the Noteholders to support a restructuring on the terms~~Company may redeem all or part of the ~~Plan. The RSA contemplates that we will file for voluntary relief under chapter 11~~2022 Second Lien Notes at redemption prices (expressed as percentages of the ~~United States Bankruptcy Code~~principal amount) equal to (i) 105.625% for the twelve-month period beginning on May 31, 2020; (ii) 105.625% for the twelve-month period beginning on May 31, 2021; and (iii) 100.000% for the twelve-month period beginning May 31, 2022 and at any time thereafter, plus accrued and unpaid interest at the redemption date. In addition, at any time prior to May 31, 2020, the Company may redeem all or ~~before December 9, 2016. See~~ ~~Overview~~.a part of the 2022 Second Lien Notes at a redemption price equal to 100% of the principal amount of the 2022 Second Lien Notes to be redeemed plus a make-whole premium, plus accrued and unpaid interest to the redemption date.

Cash Flow and Working ~~Capital.~~Capital

Net cash provided by (used in) operating activities totaled ~~$32.9~~$10.6 million during the ~~nine months ended September 30, 2016 compared to $199.0~~period of March 1, 2017 through March 31, 2017 (Successor) and ($5.9) million during the ~~comparable~~ period of January 1, 2017 through February 28, 2017 (Predecessor) compared to $29.4 million during the three months ended March 31, 2016 (Predecessor). Operating cash flows were positively impacted during the periods of March 1, 2017 through March 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor) as a result of increases in ~~2015. The decrease was primarily due to~~ the ~~decline in~~prices we received for our ~~hedge-effected~~ oil, natural gas and NGL ~~prices, the decline in natural gas~~production, and ~~NGL production volumes, restructuring fees, rig subsidy and stacking expenses, drilling rig and offshore vessel contract termination fees, partially offset by a decline~~decreases in lease operating expenses and ~~transportation, processing~~incentive compensation bonuses. Included in operating cash flows for the period of January 1, 2017 through February 28, 2017 (Predecessor) is the payment to Tug Hill of approximately $11.5 million for a break-up fee and ~~gathering ("TP&G") expenses.~~expense reimbursements upon termination of the Tug Hill PSA. See "Note 7 – Divestiture for additional information on the sale of the Appalachia Properties. See Results of Operations" below for additional information relative to commodity prices, production and operating expense variances.

Net cash ~~used in~~provided by investing activities totaled ~~$200.8~~$6.7 million during the ~~nine months ended September 30, 2016,~~period of March 1, 2017 through March 31, 2017 (Successor) and $421.0 million during the period of January 1, 2017 through February 28, 2017 (Predecessor), which primarily represents net proceeds from the sale of the Appalachia Properties, partially offset by our investment in oil and gas properties. Net cash used in investing activities totaled ~~$195.9~~$129.3 million during the ~~nine~~three months ended ~~September 30, 2015,~~March 31, 2016 (Predecessor), which primarily represents our investment in oil and gas ~~properties~~properties.

Net cash used in financing activities totaled $442.8 million during the period of ~~$385.5~~January 1, 2017 through February 28, 2017 (Predecessor), which primarily represents $341.5 million ~~offset by $179.5~~in repayments of borrowings under the Pre-Emergence Credit Agreement and $100.0 million of ~~previously restricted proceeds from~~payments to the ~~sale~~holders of ~~oil~~the 2017 Convertible Notes and ~~gas properties.~~

2022 Notes in connection with our restructuring. Net cash provided by financing activities totaled ~~$339.6~~$456.3 million during the ~~nine~~three months ended ~~September 30,~~March 31, 2016 (Predecessor), which primarily represents $477.0 million of borrowings under our ~~bank credit facility~~Pre-Emergence Credit Agreement less ~~$135.5~~$20.0 million in repayments of borrowings under our bank credit facility. Net cash used in financing activities totaled $3.1 million during the nine months ended September 30, 2015, which primarily represents net payments for share-based compensation. During the nine months ended September 30, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility.Pre-Emergence Credit Agreement.

We had a working capital ~~deficit~~ at ~~September 30, 2016~~March 31, 2017 (Successor) of ~~$159.8 million, which included $292.4 million related to~~$194.2 million.

Capital Expenditures

During the ~~2017 Convertible Notes due on~~period of March 1, ~~2017.~~2017 through March 31, 2017 (Successor), additions to oil and gas property costs of $7.0 million included $0.1 million of lease and property acquisition costs, $0.4 million of capitalized SG&A expenses (inclusive of incentive compensation) and $0.4 million of capitalized interest. During the period of January 1, 2017 through February 28, 2017 (Predecessor), additions to oil and gas property costs of $16.2 million included $3.0 million of capitalized SG&A expenses (inclusive of incentive

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~~Capital Expenditures.~~

During the three months ended September 30, 2016, additions to oil and gas property costs of $25.3 million included $0.5 million of lease and property acquisition costs, $4.8 million of capitalized SG&A expenses (inclusive of incentive compensation) and $6.9 million of capitalized interest. During the nine months ended September 30, 2016, additions to oil and gas property costs of $152.8 million included $1.7 million of lease and property acquisition costs, $17.1 million of capitalized SG&A expenses (inclusive of incentive compensation) and $21.2$2.5 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities. These additions to oil and gas property costs exclude approximately $21 million of plugging and abandonment expenditures which are recorded as a reduction of asset retirement obligations.

Contractual Obligations and Other Commitments

~~We have various~~The following table summarizes our significant contractual obligations and commitments, other ~~commitments in the normal course~~than derivative contracts, by maturity as 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. During the third quarter of 2016, we terminated an offshore vessel contract and an Appalachian drilling rig contract. Other than the terminations of the Ensco contract, offshore vessel contract and Appalachian rig contract, there have been no material changes to this disclosure during the nine months ended September 30, 2016.(Successor) (in thousands):



	Payments Due By Period
	Total		Remaining Period in 2017		Years 2018 - 2019		Years 2020 - 2021		Years 2022 and Beyond
Contractual Obligations and Commitments:
7.50% Second Lien Notes due 2022	$	225,000	$	—	$	—	$	—	$	225,000
4.20% Building Loan	11,278		307		868		944		9,159
Interest and commitment fees (1)	95,941		14,951		36,063		35,391		9,536
Asset retirement obligations including accretion	664,674		127,260		70,349		36,176		430,889
Rig commitments (2)	8,150		8,150		—		—		—
Seismic data commitments	15,380		7,690		7,690		—		—
Operating lease obligations	568		408		160		—		—
Total Contractual Obligations and Commitments	$	1,020,991	$	158,766	$	115,130	$	72,511	$	674,584


(1)	Includes interest payable on the 2022 Second Lien Notes and Building Loan. Assumes 0.375% fee on unused commitments under the Amended Credit Agreement.


(2)	Represents minimum committed future expenditures for drilling rig services.

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Results of Operations

The following ~~tables set~~table sets forth certain information with respect to our oil and gas ~~operations:~~operations for the periods presented. The period of March 1, 2017 through March 31, 2017 (Successor Company) and the period of January 1, 2017 through February 28, 2017 (Predecessor Company) are distinct reporting periods as a result of our application of fresh start accounting upon emergence from bankruptcy on February 28, 2017 and may not be comparable to prior periods.


	Three Months Ended September 30,									Successor		Predecessor
	2016		2015		Variance			% Change		Period from March 1, 2017 through March 31, 2017		Period from January 1, 2017 through February 28, 2017		Three Months Ended March 31, 2016
Production:
Oil (MBbls)	1,563		1,509		54			4	%	410		908		1,635
Natural gas (MMcf)	8,096		8,328		(232		)	(3	)%	818		5,037		6,846
NGLs (MBbls)	686		765		(79		)	(10	)%	31		408		364
Oil, natural gas and NGLs (MBoe)	3,598		3,662		(64		)	(2	)%	577		2,156		3,140
Oil, natural gas and NGLs (MMcfe)	21,590		21,972		(382		)	(2	)%
Revenue data (in thousands): (1)
Oil revenue	$	71,116	$	105,013	$	(33,897	)	(32	)%	$	20,027	$	45,837	$	60,275
Natural gas revenue	15,601		17,367		(1,766		)	(10	)%	2,210		13,476		15,173
NGLs revenue	6,666		5,980		686			11	%
NGL revenue										777		8,706		4,735
Total oil, natural gas and NGL revenue	$	93,383	$	128,360	$	(34,977	)	(27	)%	$	23,014	$	68,019	$	80,183
Average prices:
Prior to the cash settlement of effective hedging contracts
Average prices: (2)
Oil (per Bbl)	$	42.10	$	45.51	$	(3.41	)	(7	)%	$	48.85	$	50.48	$	36.87
Natural gas (per Mcf)	1.63		1.65		(0.02		)	(1	)%	2.70		2.68		2.22
NGLs (per Bbl)	9.72		7.82		1.90			24	%	25.06		21.34		13.01
Oil, natural gas and NGLs (per Boe)	23.82		24.15		(0.33		)	(1	)%	39.89		31.55		25.54
Oil, natural gas and NGLs (per Mcfe)	3.97		4.02		(0.05		)	(1	)%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	45.50	$	69.59	$	(24.09	)	(35	)%
Natural gas (per Mcf)	1.93		2.09		(0.16		)	(8	)%
NGLs (per Bbl)	9.72		7.82		1.90			24	%
Oil, natural gas and NGLs (per Boe)	25.95		35.05		(9.10		)	(26	)%
Oil, natural gas and NGLs (per Mcfe)	4.33		5.84		(1.51		)	(26	)%
Expenses (per Mcfe):
Expenses (per MBoe):
Lease operating expenses	$	0.79	$	1.10	$	(0.31	)	(28	)%	$	8.21	$	4.09	$	6.23
Transportation, processing and gathering expenses	0.49		0.83		(0.34		)	(41	)%	0.25		3.22		0.27
SG&A expenses (2)	0.71		0.89		(0.18		)	(20	)%
SG&A expenses (3)										5.76		4.47		4.06
DD&A expense on oil and gas properties	2.68		2.77		(0.09		)	(3	)%	26.89		17.05		19.25

(1)

Includes the cash settlement of effective hedging ~~contracts.~~contracts for the three months ended March 31, 2016. With respect to our 2017 and 2018 commodity derivative contracts, we have elected to not designate these contracts as cash flow hedges, and accordingly, cash settlements on our derivative contracts for periods subsequent to January 1, 2017 are reflected in derivative income (expense).


(2)	~~Excludes incentive compensation expense.~~

~~Table of Contents~~

Nine Months Ended
September 30,
2016 2015 Variance % Change
Production:
Oil (MBbls) 4,746
4,665
81
2 %
Natural gas (MMcf) 20,042
32,066
(12,024 ) (37 )%
NGLs (MBbls) 1,294
2,242
(948 ) (42 )%
Oil, natural gas and NGLs (MBoe) 9,380
12,251
(2,871 ) (23 )%
Oil, natural gas and NGLs (MMcfe) 56,282
73,508
(17,226 ) (23 )%
Revenue data (in thousands): (1)

Oil revenue $ 204,102
$ 324,105
$ (120,003 ) (37 )%
Natural gas revenue 43,327
72,611
(29,284 ) (40 )%
NGLs revenue 15,119
29,379
(14,260 ) (49 )%
Total oil, natural gas and NGL revenue $ 262,548
$ 426,095
$ (163,547 ) (38 )%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl) $ 38.86
$ 48.74
$ (9.88 ) (20 )%
Natural gas (per Mcf) 1.68
1.94
(0.26 ) (13 )%
NGLs (per Bbl) 11.68
13.10
(1.42 ) (11 )%
Oil, natural gas and NGLs (per Boe) 24.86
26.04
(1.18 ) (5 )%
Oil, natural gas and NGLs (per Mcfe) 4.14
4.34
(0.20 ) (5 )%
Including the cash settlement of effective hedging contracts
Oil (per Bbl) $ 43.01
$ 69.48
$ (26.47 ) (38 )%
Natural gas (per Mcf) 2.16
2.26
(0.10 ) (4 )%
NGLs (per Bbl) 11.68
13.10
(1.42 ) (11 )%
Oil, natural gas and NGLs (per Boe) 27.99
34.78
(6.79 ) (20 )%
Oil, natural gas and NGLs (per Mcfe) 4.66
5.80
(1.14 ) (20 )%
Expenses (per Mcfe):
Lease operating expenses $ 0.98
$ 1.08
$ (0.10 ) (9 )%
Transportation, processing and gathering expenses 0.33
0.76
(0.43 ) (57 )%
SG&A expenses (2) 0.86
0.72
0.14
19 %
DD&A expense on oil and gas properties 2.90
3.03
(0.13 ) (4 )%


~~(1)~~	~~Includes~~Prices for the ~~cash settlement~~three months ended March 31, 2016 include the realized impact of ~~effective hedging contracts.~~derivative instrument settlements, which increased the price of oil by $5.65 per Bbl and increased the price of natural gas by $0.52 per Mcf.


~~(2)~~(3)	Excludes incentive compensation expense.

Net Income/Loss. During the period of March 1, 2017 through March 31, 2017 (Successor), we reported a net loss of approximately $259.6 million ($12.98 per share) and during the period of January 1, 2017 through February 28, 2017 (Predecessor), we reported net income of approximately $630.3 million ($110.99 per share). For the three months ended ~~September 30,~~March 31, 2016, we reported a net loss totaling approximately ~~$89.6~~$188.8 million ~~or $16.01~~($33.89 per ~~share, compared to a net loss for the three months ended September 30, 2015~~share).

Write-down of $292.0 million, or $52.82 per share. During the nine months ended September 30, 2016, we reported a net loss totaling approximately $474.2 million, or $84.90 per share, compared to a net loss for the nine months ended September 30, 2015 of $772.3 million, or $139.83 per share. All per share amounts are on a diluted basis.oil and gas properties –

We follow the full cost method of accounting for oil and gas properties. During the period of March 1, 2017 through March 31, 2017 (Successor) and the three months ended ~~September 30,~~March 31, 2016 ~~and 2015,~~(Predecessor), we recognized ceiling test write-downs of our U.S. oil and gas properties totaling ~~$36.5~~$256.4 million and ~~$295.7 million, respectively. During the nine months ended September 30, 2016 and 2015, we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $284.0 million and $1,011.4~~$128.9 million, respectively. During the three months ended March 31, 2016 (Predecessor), we recognized a ceiling test write-down of our Canadian oil and gas properties, which were deemed fully impaired at the end of 2015, totaling $0.3 million. The write-downs did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity.

The ~~variance in the three~~March 31, 2017 write-down of oil and ~~nine month periods’ results~~gas properties was ~~also~~primarily due to differences between the ~~following components:~~trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017.

~~Production.~~Sale of Appalachia Properties – During the ~~three months ended September 30, 2016, total production volumes decreased to 21.6 Bcfe compared to 22.0 Bcfe produced during~~period of January 1, 2017 through February 28, 2017 (Predecessor), we recognized a $213.5 million gain on the ~~comparable 2015 period,~~sale of the Appalachia Properties, representing ~~a 2% decrease. Oil production during~~ the ~~three months ended September 30, 2016 totaled approximately 1,563 MBbls compared to 1,509 MBbls produced during~~excess of the ~~comparable 2015 period. Natural gas production totaled 8.1 Bcf during~~proceeds from the ~~three months ended September 30, 2016 compared to 8.3 Bcf during~~sale over the ~~comparable 2015 period. NGL production during the three months ended September 30, 2016 totaled approximately 686 MBbls compared to 765 MBbls produced during the comparable 2015 period.~~carrying

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amount attributed to the oil and gas properties sold, adjusted for transaction costs and other items. See Note 7 – Divestiture for additional details.

Reorganization items – During the ~~nine~~period of January 1, 2017 through February 28, 2017 (Predecessor), we recognized a net gain of $437.7 million for reorganization items. The net gain was primarily due to the gain on the discharge of debt and fresh start adjustments upon emergence from bankruptcy.

Production. During the period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 (Predecessor), total production volumes ~~decreased to 56.3 Bcfe compared to 73.5 Bcfe produced during the comparable 2015 period, representing a 23% decrease.~~were 577 MBoe, 2,156 MBoe and 3,140 MBoe, respectively. Oil production during the ~~nine~~period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 (Predecessor) totaled approximately ~~4,746~~410 MBbls, ~~compared to 4,665~~908 MBls and 1,635 MBbls, ~~produced during the comparable 2015 period.~~respectively. Natural gas production totaled ~~20.0~~0.8 Bcf, 5.0 Bcf and 6.8 Bcf during the ~~nine~~period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 ~~compared to 32.1 Bcf during the comparable 2015 period.~~(Predecessor), respectively. NGL production during the ~~nine months ended September 30, 2016 totaled approximately 1,294 MBbls compared to 2,242 MBbls produced during~~period of March 1, 2017 through March 31, 2017 (Successor), the ~~comparable 2015 period. The decreases in natural gas~~period of January 1, 2017 through February 28, 2017 (Predecessor) and ~~NGL production volumes during the nine months ended September 30, 2016 were primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016.~~

~~On October 20, 2016, we entered into the PSA for the sale of our Appalachia properties, with an expected closing date of February 27, 2017 (see "Overview –Restructuring Support Agreement~~ ~~and~~ ~~Purchase and Sale Agreement"). For~~ the three months ended ~~September~~March 31, 2016 (Predecessor), totaled approximately 31 MBbls, 408 MBbls and 364 MBbls, respectively.

Production from our deep water Amethyst well was shut-in in April 2016 to allow for a technical evaluation. On November 30, 2016, we performed a routine shut-in of the well to record pressures and determined that pressure communication existed between the production tubing and production casing strings, resulting from a suspected tubing leak. In late April 2017, we completed temporary abandonment operations, and we are evaluating the well for potential sidetrack operations, assuming we can secure an appropriate partner.

On February 27, 2017, we completed the sale of the Appalachia Properties to EQT. The Mary field in Appalachia was shut-in from September 2015 through late June 2016. The shut-in of the Mary field resulted in minimal operational activity for the Appalachia Properties for the three months ended March 31, 2016. For the period of January 1, 2017 through February 27, 2017, total production volumes attributable to ~~our~~the Appalachia ~~properties~~Properties were approximately ~~10.3 Bcfe,~~965 MBoe, comprised of ~~5.7~~3.5 Bcf of natural gas, ~~124~~57 MBbls of oil and ~~645~~330 MBbls of NGLs. For the nine months ended September 30, 2016, total production volumes attributable to our Appalachia properties were approximately 15.9 Bcfe, comprised of 9.6 Bcf of natural gas, 155 MBbls of oil and 897 MBbls of NGLs.

Prices. Prices realized during the ~~three months ended September 30, 2016~~period of March 1, 2017 through March 31, 2017 (Successor) averaged ~~$45.50~~$48.85 per Bbl of oil, ~~$1.93~~$2.70 per Mcf of natural gas and ~~$9.72~~$25.06 per Bbl of ~~NGLs, compared to average~~NGLs. Prices realized ~~prices~~during the period of ~~$69.59~~January 1, 2017 through February 28, 2017 (Predecessor) averaged $50.48 per Bbl of oil, ~~$2.09~~$2.68 per Mcf of natural gas and ~~$7.82~~$21.34 per Bbl of ~~NGLs during the comparable 2015 period.~~NGLs. Prices realized during the ~~nine~~three months ended ~~September 30,~~March 31, 2016 (Predecessor) averaged ~~$43.01~~$36.87 per Bbl of oil, ~~$2.16~~$2.22 per Mcf of natural gas and ~~$11.68~~$13.01 per Bbl of ~~NGLs, or 20% lower, on an Mcfe basis, than average realized prices of $69.48 per Bbl of oil, $2.26 per Mcf of natural gas and $13.10 per Bbl of NGLs during the comparable 2015 period. All~~NGLs. The unit pricing amounts for the three months ended March 31, 2016 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 $0.30 per Mcf and increased our average realized oil price by $3.40 per Bbl during the three months ended September 30, 2016. During the three months ended September 30, 2015, our effective hedging transactions increased our average realized natural gas price by $0.44 per Mcf and increased our average realized oil price by $24.08 per Bbl. During the nine months ended September 30,March 31, 2016, our effective hedging transactions increased our average realized natural gas price by ~~$0.48~~$0.52 per Mcf and increased our average realized oil price by ~~$4.15~~$5.65 per Bbl. ~~During the nine months ended September 30, 2015,~~With respect to our ~~effective hedging transactions increased~~2017 and 2018 derivative contracts, we elected to not designate these contracts as cash flow hedges for accounting purposes, and accordingly, settlements on our ~~average realized natural gas price by $0.32 per Mcf~~derivative contracts are now recognized in earnings through derivative income (expense). See Known Trends and ~~increased our average realized oil price by $20.74 per Bbl.~~Uncertainties.

Revenue. Oil, natural gas and NGL revenue was ~~$93.4~~$23.0 million, ~~during~~$68.0 million and $80.2 million for the period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 ~~compared to $128.4 million during the comparable period of 2015. For the nine months ended September 30, 2016 and 2015, oil, natural gas and NGL revenue totaled $262.5 million and $426.1 million,~~(Predecessor), respectively. The ~~decrease~~increase in total revenue ~~for the three months ended September 30, 2016~~in 2017 was primarily due to ~~a 2% decrease in production volumes and a 35% decrease~~an increase in average realized oil ~~prices from~~and natural gas prices. For the ~~comparable~~ period of 2015. The decrease in total revenue for the nine months ended September 30, 2016 was primarily due to a 23% decrease in production volumes and a 20% decrease in average realized prices on an equivalent basis from the comparable period of 2015. For the three and nine months ended September 30, 2016,January 1, 2017 through February 27, 2017, total oil, natural gas and NGL revenues attributable to ~~our~~the Appalachia ~~properties~~Properties were ~~$16.5 million and $27.7 million, respectively.~~$18.6 million.

Derivative Income/Expense. ~~Net derivative expense for~~For the three months ended ~~September 30,~~March 31, 2016, net derivative income totaled ~~$0.2~~$0.1 million, comprised of $0.3 million of income from cash settlements and $0.2 million of non-cash expense resulting from changes in the fair value of unsettled derivative ~~instruments~~instruments. With respect to our 2017 and ~~an immaterial~~2018 commodity derivative contracts, we elected to not designate these contracts as cash ~~settlement. For~~flow hedges for accounting purposes. Accordingly, the ~~three months ended September 30, 2015,~~ net changes in the mark-to-market valuations and the monthly settlements on these derivative ~~expense~~contracts are recorded in earnings in derivative income (expense). Net derivative income for the period of March 1, 2017 through March 31, 2017 (Successor) totaled ~~$2.4~~$2.6 million, comprised of ~~$5.3~~$2.5 million of non-cash income resulting from changes in the fair value of derivative instruments, $0.2 million of income from cash settlements and ~~$2.9~~$0.1 million of non-cash expense for the amortization of the cost of the puts. Net derivative expense for the period of January 1, 2017 through February 28, 2017 (Predecessor) totaled $1.8 million, comprised of $1.7 million of non-cash expense resulting from changes in the fair value of ~~unsettled~~ derivative ~~instruments. Net derivative expense for the nine months ended September 30, 2016 totaled $0.7 million, comprised of $0.6 million of income from cash settlements~~instruments and ~~$1.3~~$0.1 million of non-cash expense ~~resulting from changes in~~for the ~~fair value~~amortization of ~~unsettled derivative instruments. For~~ the nine months ended September 30, 2015, net derivative income totaled $4.9 million, comprised of $15.7 million of income from cash settlements and $10.8 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.puts.

Expenses. Lease operating expenses ~~during~~for the period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 ~~and 2015~~(Predecessor), totaled ~~$17.0~~$4.7 million, $8.8 million and ~~$24.2 million, respectively. For the nine months ended September 30, 2016 and 2015, lease operating expenses totaled $55.3 million and $79.3~~$19.5 million, respectively. On a unit of production basis, lease operating expenses were ~~$0.79~~$8.21 per ~~Mcfe~~Boe, 4.09 per Boe and ~~$1.10~~$6.23 per ~~Mcfe~~Boe for the period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 ~~and 2015, respectively, and $0.98 per Mcfe and $1.08 per Mcfe for the nine months ended September 30, 2016 and 2015,~~(Predecessor), respectively. The decrease in lease operating expenses during the three and nine months ended September 30, 2016 was primarily attributable to service cost reductions, the implementation of cost-savings measures, operatingOperating efficiencies and the shut-in of production at our Mary field from September 2015 until late June 2016. For the three and nine months ended September 30, 2016, lease operating expenses attributable to our Appalachia properties were $2.9 million and $9.0 million, respectively.implementation

TP&G expenses during the three months ended September 30, 2016 and 2015 totaled $10.6 million and $18.2 million, respectively, or $0.49 per Mcfe and $0.83 per Mcfe, respectively. For the nine months ended September 30, 2016 and 2015, TP&G expenses totaled $18.7 million and $55.9 million, respectively, or $0.33 per Mcfe and $0.76 per Mcfe, respectively. The decrease in TP&G expenses

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~~during~~of cost-savings measures resulted in decreases in lease operating expenses in 2017. For the period of January 1, 2017 through February 27, 2017, lease operating expenses attributable to the Appalachia Properties totaled $2.3 million.

Transportation, processing and gathering ("TP&G") expenses for the period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 ~~was due primarily to the beneficial terms of the interim gas gathering~~(Predecessor), totaled $0.1 million, $6.9 million and ~~processing agreement in Appalachia that was executed at the end of the second quarter of 2016. The decrease in~~$0.8 million, respectively, or $0.25 per Boe, $3.22 per Boe and $0.27 per Boe, respectively. TP&G expenses ~~during~~for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 ~~was primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016, as well as the~~(Predecessor) included an approximate $4 million recoupment of previously paid transportation costs allocable to the Federal government's portion of certain of our deep water production. The shut-in of production ~~which amounted~~at the Mary field in Appalachia during the three months ended March 31, 2016 (Predecessor) also contributed to ~~approximately $4 million.~~the lower amount of TP&G expenses in that period. For the ~~three and nine months ended September 30, 2016,~~period of January 1, 2017 through February 27, 2017, TP&G expenses attributable to ~~our~~the Appalachia ~~properties were $9.6 million and $17.2 million, respectively.~~Properties totaled approximately $6.8 million.

Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 (Predecessor), totaled ~~$57.8~~$15.5 million, ~~compared to $60.8 million during the comparable period of 2015. For the nine months ended September 30, 2016 and 2015, DD&A expense totaled $163.4~~$36.8 million and ~~$222.8~~$60.4 million, respectively. On a unit of production basis, DD&A expense was ~~$2.68~~$26.89 per ~~Mcfe~~Boe, $17.05 per Boe and ~~$2.77~~$19.25 per ~~Mcfe~~Boe during the period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 ~~and 2015,~~(Predecessor), respectively. For the nine months ended September 30, 2016 and 2015, DD&A expense, on a unit of production basis, was $2.90 per Mcfe and $3.03 per Mcfe, respectively. The decrease in DD&A during the three and nine months ended September 30, 2016 was primarily due to the ceiling test write-downs of our oil and gas properties.

Other operational expenses for the period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 ~~and 2015~~(Predecessor) totaled ~~$9.1~~$0.7 million, $0.5 million and ~~$0.4~~$12.5 million, respectively. Included in other operational expenses for the three months ended ~~September 30,~~March 31, 2016 are $7.5 million in charges related to the terminations of an offshore vessel contract and an Appalachian drilling rig contract and approximately $1.7 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Appalachian drilling rig and the platform rig at Pompano. For the nine months ended September 30, 2016 and 2015, other operational expenses totaled $49.3 million and $1.6 million, respectively. Included in other operational expenses for the nine months ended September 30, 2016 are the $7.5 million in charges for the offshore vessel and Appalachian drilling rig contract terminations, a $20 million charge related to the termination of our deep water drilling rig contract with Ensco in June 2016, approximately $15.3 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Appalachian drilling rig and the platform rig at Pompano, and(Predecessor) is a $6.0 million cumulative foreign currency translation loss on the substantial liquidation of our former foreign subsidiary, Stone Energy Canada ULC, which was reclassified from accumulated other comprehensive income. Also included in other operational expenses for the three months ended March 31, 2016 are approximately $6.1 million of rig subsidy charges related to the farm out of the ENSCO 8503 deep water drilling rig and stacking charges related to an Appalachian drilling rig.

SG&A expenses (exclusive of incentive compensation) for the ~~three months ended September 30, 2016 were $15.4 million compared to $19.6 million for~~period of March 1, 2017 through March 31, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30, 2015. For the nine months ended September 30,~~March 31, 2016 ~~and 2015, SG&A expenses (exclusive of incentive compensation) totaled $48.2~~(Predecessor) were $3.3 million, $9.6 million and ~~$53.0~~$12.8 million, respectively. On a unit of production basis, SG&A expenses were ~~$0.71~~$5.76 per ~~Mcfe~~Boe, $4.47 per Boe and ~~$0.89~~$4.06 per ~~Mcfe~~Boe, respectively.

For the period of January 1, 2017 through February 28, 2017 (Predecessor), incentive compensation expense totaled $2.0 million and represented payments made to the Company's executives pursuant to the KEIP. Incentive compensation expense for the three months ended ~~September 30,~~March 31, 2016 and 2015, respectively. For the nine months ended September 30, 2016 and 2015, SG&A expenses, on a unit of production basis, were $0.86 per Mcfe and $0.72 per Mcfe, respectively. The decrease in SG&A expenses for the three and nine months ended September 30, 2016 was primarily attributable to staff and other cost reductions. SG&A expenses for the three months ended September 30, 2015 included $2.1 million of lease termination charges associated with the early termination of an office lease.

~~For the three and nine months ended September 30, 2016, restructuring fees~~(Predecessor) totaled ~~$5.8~~$5.0 million and ~~$16.2 million, respectively. These fees~~ related to ~~expenses supporting a restructuring effort including legal and financial advisory costs for Stone, our bank group and our noteholders.~~

~~For~~ the ~~three months ended September 30, 2016 and 2015,~~accrual of estimated incentive compensation expense totaled $2.2 million and $0.8 million, respectively. For the nine months ended September 30, 2016 and 2015, incentive compensation expense totaled $11.8 million and $3.6 million, respectively. The 2016 incentive compensation cash bonuses, ~~are~~which were calculated based on the projected 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~~fiscal year.

Interest expense infor the ~~2016 periods as compared to~~period of March 1, 2017 through March 31, 2017 (Successor) totaled $1.2 million, net of $0.4 million of capitalized interest, and included interest expense associated with the ~~2015 periods.~~

2022 Second Lien Notes. Interest expense for the three months ended ~~September 30,~~March 31, 2016 (Predecessor) totaled ~~$16.9~~$15.2 million, net of ~~$6.9~~$7.4 million of capitalized interest, compared to interest expense of $10.9 million, net of $10.3 million of capitalized interest, during the comparable 2015 period. For the nine months ended September 30, 2016, interest expense totaled $49.8 million, net of $21.2 million of capitalized interest, compared to interest expense of $31.7 million, net of $31.9 million of capitalized interest, during the comparable 2015 period. The increase in interest expense was primarily the result ofand included interest expense associated with ~~the increased~~ borrowings under our ~~bank credit facility~~Pre-Emergence Credit Agreement and ~~a decrease~~the 2017 Convertible Notes and 2022 Notes. Upon emergence from bankruptcy on February 28, 2017, pursuant to the terms of the Plan, the 2017 Convertible Notes and 2022 Notes were cancelled and outstanding borrowings under the Pre-Emergence Credit Agreement were paid in ~~the amount of interest capitalized to oil and gas properties.~~full.

For the ~~nine~~period of January 1, 2017 through February 28, 2017 (Predecessor) and the three months ended ~~September 30,~~March 31, 2016 ~~and 2015,~~(Predecessor) we recorded an income tax provision ~~(benefit)~~ of ~~$6.8~~$3.6 million and ~~($280.8)~~$1.8 million, respectively. ~~The income tax benefit recorded for the nine months ended September 30, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs of our oil and gas properties.~~ As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, 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~~We also established a valuation allowance against a portion of our deferred tax assets upon emergence from bankruptcy as part of fresh start accounting, and the subsequent change in the valuation allowance was recorded as an adjustment to the income tax ~~expense.~~provision.

Off-Balance Sheet Arrangements

None.

Recent Accounting Developments

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers" to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 15, 2017. We expect to apply the modified retrospective approach

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~~Off-Balance Sheet Arrangements~~

~~None.~~

~~Recent Accounting Developments~~upon adoption of this standard. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

~~In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230) , Classification of Certain Cash Receipts and Cash Payments~~" to reduce diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The standard is effective for public entities for fiscal years beginning after December 15, 2017, and 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 2016-15 in the same period, and any adjustments should be reflected as of the beginning of the fiscal year that includes that interim 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.~~statements.

Defined Terms

Oil, condensate and NGLs are stated in barrels ~~(“Bbls”~~("Bbls") or thousand barrels ~~(“MBbls”~~("MBbls"). Natural gas is stated in billion cubic feet ~~(“Bcf”~~("Bcf"), million cubic feet ~~(“MMcf”~~("MMcf") or thousand cubic feet ~~(“Mcf”~~("Mcf"). ~~Oil, condensate and NGLs are converted to natural gas at a~~A barrel of oil equivalent (Boe) is determined by using the ratio of one ~~barrel~~Bbl of ~~liquids per~~oil or NGLs to 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.

~~Item~~ITEM 3. ~~Quantitative and Qualitative Disclosures About Market Risk~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. For the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2017, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate ~~$17.8 million impact on our revenues. Excluding the effects of hedging contracts, a 10% fluctuation in realized oil and natural gas prices would have had an approximate $23.3~~$8.5 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 ~~November 7, 2016~~May 8, 2017 have hedged approximately ~~25%~~35% of our estimated ~~2016~~2017 production from estimated proved reserves and 22% of our estimated 2018 production from estimated proved reserves. ~~Although we~~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. Pursuant to requirements under the Plan, we expect to hedge approximately 50% of our estimated production from estimated proved producing reserves for each of 2017 and 2018. See Part I, Item 1. Financial Statements – Note 49 – Derivative Instruments and Hedging Activities, of this Form 10-Q for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Since the filing of our ~~2015~~2016 Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to commodity prices.

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Interest Rate Risk

We had total debt outstanding of ~~$1,428~~$236 million at ~~September 30, 2016,~~March 31, 2017, all of which ~~$1,086 million, or 76%,~~ bears interest at fixed rates. The ~~$1,086~~$236 million of fixed-rate debt is comprised of ~~$300~~$225 million of the ~~2017 Convertible Notes, $775 million of the~~ 2022 Second Lien Notes and $11 million of the Building Loan. ~~At September 30, 2016, the remaining $342 million of our outstanding debt bears interest at~~

Our bank credit facility is subject to an adjustable interest ~~rate and consists of borrowings outstanding under our bank credit facility.~~rate. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources of this Form 10-Q. ~~Borrowings~~We had no outstanding borrowings under our Amended Credit Agreement as of March 31, 2017. If we borrow funds under our bank credit facility, we may be 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 September 30, 2016, the weighted average interest rate under our bank credit facility was approximately 3.1% per annum.~~

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ITEM 4. ~~Controls and Procedures~~CONTROLS AND PRODECURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of ~~September 30, 2016~~March 31, 2017 at the reasonable assurance level.

Changes in Internal Controls Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended ~~September 30, 2016~~March 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

~~Item~~ITEM 1. ~~Legal Proceedings~~LEGAL PROCEEDINGS

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

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“("Jefferson ~~Parish”~~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”~~"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. AIn March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. On November 10, 2016, a decision dismissing a Jefferson Parish Coastal Zone Management ("CZM") test case ~~in Jefferson Parish was recently dismissed for~~ failure to exhaust administrative remedies was reversed. Defendants in the test case are seeking appellate review. Shortly after Stone filed a ~~conclusion that is being challenged~~suggestion of bankruptcy in December 2016, Jefferson Parish dismissed two of its three CZM suits against Stone without prejudice to refiling. As set forth below under “Chapter 11 Proceedings,” Stone emerged from bankruptcy effective February 28, 2017, and the bankruptcy cases were closed by order of the ~~Louisiana Department of Natural Resources ("LDNR").~~Bankruptcy Court on April 20, 2017.

In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“("Plaquemines ~~Parish”~~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 CZM suits filed by the Plaquemines Parish. OnIn March and April 7, 2016, the ~~LDNR~~Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit, and the Plaquemines Parish Council rescinded their resolution to dismiss all CZM suits filed by the Parish. Shortly after Stone filed a ~~Petition for Intervention~~suggestion of bankruptcy in ~~this lawsuit.~~December 2016, Plaquemines Parish dismissed its CZM suit against Stone without prejudice to refiling. As set forth below under “Chapter 11 Proceedings,” Stone emerged from bankruptcy effective February 28, 2017, and the bankruptcy cases were closed by order of the Bankruptcy Court on April 20, 2017.

On November 17, 2014, the Pennsylvania Department of Environmental Protection ~~(“PADEP”~~("PADEP") issued a Notice of Violation ~~(“NOV”~~("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”~~("Southwestern"). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. Reclamation of the site by Southwestern, with the participation of the PADEP and Stone, is now complete. The PADEP may impose a penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.

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

Chapter 11 Proceedings

On December 14, 2016, the Debtorsfiled Bankruptcy Petitions in the United States Bankruptcy Court for the Southern District of Texas, Houston Division seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect pre-petition liabilities or to exercise control over the property of the Debtors. On February 15, 2017, the Bankruptcy Court entered the Confirmation Order confirming the Plan, as modified by the Confirmation Order, and on February 28, 2017, the Plan became effective and the Debtors emerged from bankruptcy, with the bankruptcy cases then being closed by Final Decree Closing Chapter 11 Cases and Terminating Claims Agent Services entered by the Bankruptcy Court on April 20, 2017. For additional information on the bankruptcy proceedings, see Part I. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

~~Item~~

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ITEM 1A. ~~Risk Factors~~RISK FACTORS

The following updates the Risk Factors included in our ~~2015~~2016 Annual Report on Form 10-K. Except as set forth below, there have been no material changes with respect to Stone’s risk factors previously reported in Part I, Item 1A, of our ~~2015~~2016 Annual Report on Form 10-K.

~~Risks Relating to the Restructuring Support Agreement~~

The Restructuring Support Agreement (the “RSA”) is subject to significant conditions and milestones that may be beyond our control and may be difficult for us to satisfy. If the RSA is terminated, our ability to confirm and consummate the pre-packagedOur plan of reorganization ~~(the"Plan"~~(the “Plan”) ~~could~~is based in large part upon assumptions and analyses developed by us. Our actual financial results may vary materially from the projections that we filed in connection with the Plan. If these assumptions and analyses prove to be ~~materially and adversely affected.~~incorrect, the Plan may be unsuccessful in its execution.

The RSA contains certain covenants on the part of the Company and certain (i) holders of the Company’s 1 ¾% Senior Convertible Notes due 2017 (the “Convertible Notes”) and (ii) holders of the Company’s 7 ½% Senior Notes due 2022 (together with the Convertible Notes, the “Notes”Plan affects both our capital structure and the ~~holders thereof, the “Noteholders”) who are signatories to the RSA, including that the Noteholders will vote in favor of the Plan, support the sale by us~~ownership, structure and operation of our ~~approximately 86,000 net acres in the Appalachia regions~~business and reflects assumptions and analyses based on our experience and perception of Pennsylvania and West Virginia (the “Properties”) and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the RSA. The RSA sets forth certain conditions we must satisfy, including the timely satisfaction of certain milestones in the chapter 11 proceeding set forth in Schedule 1 to the RSA, as amended by the RSA Amendment, such as confirmation of the Plan and effectiveness of the Plan. The consummation of the Plan will be subject to customaryhistorical trends, current conditions and ~~other requirements,~~expected future developments, as well as other factors that we consider appropriate under the ~~sale by us~~circumstances. In addition, the Plan relies upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. The financial projections were prepared solely for the purpose of the ~~Properties for a cash purchase price~~bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. Financial forecasts are necessarily speculative, and it is likely that one or more of ~~at least $350 million~~the assumptions and ~~approval~~estimates that were the basis of ~~a United States Bankruptcy Court (the “Bankruptcy Court”). Our ability to timely complete such milestones is subject to risks and uncertainties that may~~these financial forecasts will not be ~~beyond~~accurate. In our ~~control.~~

~~The RSA also provides for termination by each party, or by either party, upon~~case, the ~~occurrence of certain events, including without limitation, termination by the Required Consenting Noteholders (as defined~~forecasts were even more speculative than normal, because they involved fundamental changes in the ~~RSA) upon the failure~~nature of ~~the Company to achieve~~

~~Table~~our capital structure. Accordingly, we expect that our actual financial condition and results of ~~Contents~~

~~certain milestones set forth in Schedule 1 to the RSA, as amended by the RSA Amendment. For example, the Noteholders~~operations will differ, perhaps materially, from what we have the option to terminate the RSA at any time that the Noteholders determine, in their sole discretion, that the total amount of all cure amounts or other payment obligations of Stone arising or resulting from the assumption of executory contracts or unexpired leases exceeds an amount acceptable to the Noteholders. If the RSA is terminated, each of the parties thereto will be released from their obligations in accordance with the terms of the RSA. Such termination may result in the loss of support for the Plan by the parties to the RSA, which could adversely affect our ability to confirm and consummate the Plan. If the Plan is not consummated,anticipated. Consequently, there can be no assurance that ~~any new plan of reorganization would be as favorable to holders of claims as~~ the ~~current~~results or developments contemplated by the Plan will occur or, even if they do occur, that they will have the anticipated effects on us and our ~~chapter 11 proceedings~~subsidiaries or our business or operations. The failure of any such results or developments to materialize as anticipated could ~~become protracted, which could significantly and detrimentally impact our relationships with vendors, suppliers, employees and customers.~~

~~Although we intend to pursue~~materially adversely affect the ~~restructuring in accordance with the terms set forth in the RSA and the RSA Amendment, there can be no assurance that we will be~~ successful ~~in completing a restructuring or any other similar transaction on the terms set forth in the RSA and the RSA Amendment, on different terms or at all.~~

~~We will be subject to the risks and uncertainties associated with chapter 11 proceedings.~~

~~The RSA contemplates that the Company will file for voluntary relief under chapter 11~~execution of the Bankruptcy Code in the Bankruptcy Court on or before December 9, 2016 to implement the Plan in accordance with the term sheet annexed to the RSA. As a consequence of our filing for relief under chapter 11 of the Bankruptcy Code, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, will be subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

~~our ability to prosecute, confirm and consummate the Plan or another plan of reorganization with respect to the chapter 11 proceedings;~~

~~the high costs of bankruptcy proceedings and related fees;~~

~~our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;~~

~~our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;~~

~~our ability to maintain contracts that are critical to our operations;~~

~~our ability to execute our business plan in the current depressed commodity price environment;~~

~~the ability to attract, motivate and retain key employees;~~

~~the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;~~

~~the ability of third parties to seek and obtain court approval to convert the chapter 11 proceedings to chapter 7 proceedings; and~~

~~the actions and decisions of our creditors and other third parties who have interests in our chapter 11 proceedings that may be inconsistent with our plans.~~Plan.

~~Delays in our chapter 11 proceedings increase the risks of our inability to reorganize our business and emerge from bankruptcy and may increase our costs associated with the bankruptcy process.~~

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact of events that occur during our chapter 11 proceedings that may be inconsistent with our plans.

~~We may not be able to obtain confirmation of the Plan as outlined in the RSA.~~

There can be no assurance that the Plan as outlined in the RSA (or any other plan of reorganization) will be approved by the Bankruptcy Court, so we urge caution with respect to existing and future investments in our securities.

The success of any reorganization will depend on approval by the Bankruptcy Court and the willingness of existing debt and security holders to agree to the exchange or modification of their interests as outlined in the Plan, and there can be no guarantee of success with respect to the Plan or any other plan of reorganization. We might receive official objections to confirmation of the Plan from the various bankruptcy committees and stakeholders in the chapter 11 proceedings. We cannot predict the impact that any objection might have on the Plan or on a Bankruptcy Court's decision to confirm the Plan. Any objection may cause us to devote significant resources in response which could materially and adversely affect our business, financial condition and results of operations.

If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if any, distributions holders of claims against us, including holders of our secured and unsecured debt and equity, would ultimately receive with respect to their claims. Once commenced, there can be no assurance as to whether we will successfully reorganize and emerge from chapter 11 or, if we do successfully reorganize, as to when we would emerge from chapter 11. If no plan of reorganization can be confirmed,

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or if the Bankruptcy Court otherwise finds that it would be in the best interest of holders of claims and interests, the chapter 11 cases may be converted to cases under chapter 7 of the Bankruptcy Code, pursuant to which a trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code.

~~Upon emergence from bankruptcy, our~~Our historical financial information may not be indicative of our future financial performance.

~~Our capital structure will be significantly altered under the Plan. Under fresh-start reporting rules that may apply to us upon~~

On February 28, 2017, the effective date of ~~the Plan (or any alternative plan of reorganization),~~our emergence from bankruptcy, we adopted fresh start accounting and consequently, our assets and liabilities ~~would be~~were adjusted to fair values and our accumulated deficit ~~would be~~was restated to zero. Accordingly, ~~if fresh-start reporting rules apply,~~ our financial condition and results of operations following our emergence from ~~chapter~~Chapter 11 ~~would~~will not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

The pursuit of the RSA has consumed, and the chapter 11 proceedings will continue to consume, a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

Although the Plan is designed to minimize the length of our chapter 11 proceedings, it is impossible to predict with certainty the amount of time that we may spend in bankruptcy or to assure parties in interest that the Plan will be confirmed. The chapter 11 proceedings will involve additional expense and our management will be required to spend a significant amount of time and effort focusing on the proceedings. This diversion of attention may materially adversely affect the conduct of our business, and, as a result ~~our financial condition and results of operations, particularly if the chapter 11 proceedings are protracted.~~

~~During the pendency~~ of the chapter 11 proceedings, our employees will face considerable distraction and uncertainty, and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to effectively, efficiently and safely conduct our business, and could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

~~Trading in our securities is highly speculative and poses substantial risks. Under the Plan, following effectiveness~~implementation of the Plan and the ~~holders~~transactions contemplated thereby, our historical financial information may not be indicative of our existing common stock will receive their pro rata share of 5% of the common stock in the reorganized Company and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants, which interests could be further diluted by the warrants and the management incentive plan contemplated by the Plan.future financial performance.

The Plan, as contemplated in the RSA, provides that upon the Company's emergence from chapter 11, Noteholders will receive their pro rata share of (a) $150 million of the net cash proceeds from the sale of the Properties plus 85% of the net cash proceeds from the sale of the Properties in excess of $350 million, if any, (b) 95% of the common stock in the reorganized Company and (c) $225 million of new 7.5% second lien notes due 2022 and that the holders of the existing common stock of the Company will receive their pro rata share of 5% of the common stock in the reorganized Company and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. If the Plan as contemplated in the RSA is confirmed, up to 10% of the equity interests in the reorganized Company will be reserved for issuance as awards under a post-restructuring management incentive plan. Issuances of common stock (or securities convertible into or exercisable for common stock) under the management incentive plan and any exercises of the warrants for shares of common stock will dilute the voting power of the outstanding common stock and may adversely affect the trading price of such common stock.

Upon ~~our~~ emergence from bankruptcy, the composition of our board of directors ~~may change~~changed significantly.

Under the Plan, the composition of our board of directors ~~may change~~changed significantly. Upon emergence, the board will be made up of seven directors selected by the Required Consenting Noteholders, one of which will be our Chief Executive Officer. The Required Consenting Noteholders have agreed to interview any of the existing membersAll of our board ~~who wishes to continue as a member of our board. However, it is possible that up to six of our seven board~~ members ~~may be~~are new to the Company. ~~Any~~Our new directors ~~are likely to~~ have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

~~Assuming the Plan were effective as of the date hereof, it is estimated that twelve bondholders who~~

Funds advised by two significant stockholders currently hold approximately ~~85% of the Notes would own over 80%~~36% and 20%, respectively, of our post-reorganization common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares

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or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

~~We have substantial liquidity needs and may not be able to obtain sufficient liquidity to confirm a plan of reorganization and exit bankruptcy.~~

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout the chapter 11 proceedings. There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the chapter 11 proceedings, allow us to proceed with the confirmation of a chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of any cash collateral order that may be entered by the Bankruptcy Court in connection with the chapter 11 proceedings, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate the Plan or any other chapter 11 plan of reorganization, and (v) the cost, duration and outcome of the chapter 11 proceedings.

The Plan and any other plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our Plan may be unsuccessful in its execution.

The Plan and any other plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

In addition, the Plan and any other plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

~~We may be subject to claims that will not be discharged in our chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.~~

The Bankruptcy Code provides that the confirmation of a chapter 11 plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a chapter 11 plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

~~Even if a chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.~~

Even if the Plan or any other chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our

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~~oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other chapter 11 plan of reorganization will achieve our stated goals.~~

Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of our chapter 11 proceedings. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if the Plan is confirmed.

~~For the duration of the chapter 11 proceedings, we may not be able to enter into commodity derivatives covering estimated future production on favorable terms or at all.~~

During the chapter 11 proceedings, our ability to enter into new commodity derivatives covering estimated future production will be dependent upon either entering into unsecured hedges or obtaining Bankruptcy Court approval to enter into secured hedges. As a result, we may not be able to enter into additional commodity derivatives covering production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

Transfers or issuances of our equity before or in connection with our chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We had net operating loss carryforwards of approximately $336 million as of December 31, 2015. We believe that our consolidated group will generate additional net operating losses for the 2016 tax year. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce our U.S. federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change”, as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an "ownership change" if one or more stockholders owning 5% or more of a corporation's common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change”, the amount of its net operating losses that may be utilized to offset future table income generally is subject to an annual limitation. Even if the net operating loss carryforwards are subject to limitation under Section 382, the net operating losses can be further reduced by the amount of discharge of indebtedness arising in a chapter 11 case under Section 108 of the Internal Revenue Code.

We expect to request that the Bankruptcy Court approve restrictions on certain transfers of our stock to limit the risk of an "ownership change" prior to our restructuring in our chapter 11 proceedings. Following the implementation of a plan of reorganization, it is likely that an “ownership change” will be deemed to occur and our net operating losses will nonetheless be subject to annual limitation.

~~Risks Relating to the Purchase and Sale Agreement~~ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The Purchase and Sale Agreement (the “PSA”) providing for the sale by us of the Properties to Tug Hill (the “Disposition”) is subject to significant conditions and milestones that may be beyond our control and may be difficult for us to satisfy. If the PSA is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.

The PSA contains customary representations, warranties and covenants. The parties expect to close the Disposition by February 27, 2017, subject to customary closing conditions and approval by the Bankruptcy Court. The PSA may be terminated, subject to certain exceptions, (1) upon mutual written consent, (2) if the closing has not occurred by March 1, 2017, (3) for certain material breaches of representations and warranties or covenants that remain uncured, (4) if, on or prior to the end of the Diligence Period on December 19, 2016, title and environmental defect amounts (after application of customary thresholds and deductibles), casualty losses and the value of any assets excluded from the Properties due to the exercise of preferential purchase rights or consents equal or exceed $10 million in the aggregate, (5) if we fail to file for bankruptcy on or before December 9, 2016, (6) if the Bankruptcy Court does not enter an order approving our assumption of the PSA and certain other matters within 30 days of our filing for bankruptcy, (7) if the Bankruptcy Court does not enter a sale order for the Disposition by February 10, 2017, and (8) upon the occurrence of certain other events specified in the PSA. The consummation of the Plan will be subject to customary conditions and other requirements, as well as the sale by us of the Properties for a cash purchase price of at least $350 million and approval of the Bankruptcy Court. If the PSA is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.

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Following the Disposition of the Properties, our production, revenue and cash flow from operating activities will be derived from assets that are concentrated in a single geographic area in the GOM. Approximately 72% of our production during the first nine months of 2016 was associated with our GOM deep water, Gulf Coast deep gas and GOM conventional shelf properties. Unlike other entities that are geographically diversified, we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may:

~~subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate; and~~

~~result in our dependency upon a single or limited number of hydrocarbon basins.~~

~~In addition, the geographic concentration of our properties in the GOM and the U.S. Gulf Coast means that some or all of the properties could be affected should the region experience:~~

~~severe weather, such as hurricanes and other adverse weather conditions;~~

~~delays or decreases in production, the availability of equipment, facilities or services;~~

~~delays or decreases in the availability of capacity to transport, gather or process production; and/or~~

changes in the regulatory environment such as the new guidelines recently issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the outer continental shelf.

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the GOM during the initial few years when compared to other regions in the United States. Typically, 50% of the reserves of properties in the GOM are depleted within three to four years with natural gas wells having a higher rate of depletion than oil wells. Due to high initial production rates, production of reserves from reservoirs in the GOM generally decline more rapidly than from other producing reservoirs. As a result of the concentration of our operations in the GOM, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue.

In addition, we are particularly vulnerable to significant risk from hurricanes and tropical storms in the GOM. In past years, we have experienced shut-ins and losses of production due to the effects of hurricanes in the GOM. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses.

Because all or a number of our properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

~~Other Risks~~

New guidelines recently issued by the federal Bureau of Ocean Energy Management ("BOEM") related to financial assurance requirements to cover decommissioning obligations for operations on the outer continental shelf may have a material adverse effect on our business, financial condition, or results of operations.

On July 14, 2016, BOEM issued a Notice to Lessees and Operators ("NTL") that augments requirements for the posting of additional financial assurance by offshore lessees, among others, to assure that sufficient funds are available to perform decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The NTL, effective September 12, 2016, does away with the agency’s past practice of waiving supplemental bonding obligations where a company could demonstrate a certain level of financial strength. Instead, BOEM will allow companies to “self-insure”, but only up to 10% of a company’s “tangible net worth”, which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and, consistent with those procedures, BOEM has tentatively proposed an implementation timeline that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) “Self-Insurance” letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) “Proposal” letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) “Order” letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a “tailored plan” for posting additional security over a phased-in period of time, (B) within 60 days

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of such letter, provide additional security for “sole liability” properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan). BOEM tentatively expects to approve or deny tailored plans submitted by lessees on or around September 11, 2017, although extensions may be granted to companies actively working with BOEM to finalize tailored plans. We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are not eligible to self-insure any of our additional security obligations. We received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security will be required, and we intend to work with BOEM to adjust our previously submitted tailored plan for the provision of new financial assurances required to be posted as a result of the new NTL. Our revised proposed plan would require approximately $35 million to $40 million of incremental financial assurance or bonding for 2016 through 2017, a portion of which may require cash collateral. Under the revised plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM. 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.

~~The closing market price~~Shares of our common stock has recently declined significantly. On April 29 and May 17, 2016, we were notified by the NYSE that our common stock was not in compliance with NYSE listing standards. If we are unable to cure the market capitalization deficiency, our common stock could be delisted from the NYSE or trading could be suspended.

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

On April 29, 2016, we were notified by the NYSE that the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days. 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.

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. 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 had 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 accepted the plan on August 4, 2016 and will continue to review the Company on a quarterly basis for compliance with the plan. Upon acceptance of the plan by the NYSE, and after two consecutive quarters of sustained market capitalization above $50 million, we would no longer be non-compliant with the market capitalization and stockholders' equity requirements. During the 18-month cure period, our shares of common stock will continue to be listed and traded on the NYSE, unless we experience other circumstances that subject us to delisting. If we fail to meet the material aspects of the plan or any of the quarterly milestones, the NYSE will review the circumstances causing the variance, and determine whether such variance warrants commencement of suspension and delisting procedures. Upon a delisting from the NYSE, we would commence trading on the OTC Pink. On September 20, 2016, we submitted our quarterly update to the business plan for the second of quarter 2016 and the NYSE notified us that it accepted the quarterly update on September 22, 2016.

Under Section 802.01D of the NYSE Listed Company Manual, if a company that is below a continued listing standard files or announces an intent to file for relief under chapter 11 of the Bankruptcy Code, the company is subject to immediate suspension and delisting. However, if we are profitable or have positive cash flow, or if we are demonstrably in sound financial health despite the bankruptcy proceedings, the NYSE may evaluate our plan in light of the filing or announcement of intent to file without immediate suspension and delisting of our common stock.

In addition to potentially commencing suspension or delisting procedures in respect of our common stock if we fail to meet the material aspects of the plan or any of the quarterly milestones or if we file for bankruptcy and do not have positive cash flow or are not in sound financial health, 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

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deficiency, and our shares would be delisted immediately and suspended from trading on the NYSE. The commencement of suspension or delisting procedures by an exchange remains, at all times, at the discretion of such exchange and would be publicly announced by the exchange. If a suspension or delisting were to occur, there would be significantly less liquidity in the suspended or delisted securities. In addition, our ability to raise additional necessary capital through equity or debt financing, and attract and retain personnel by means of equity compensation, would be greatly impaired. Furthermore, with respect to any suspended or delisted securities, we would expect decreases in institutional and other investor demand, analyst coverage, market making activity and information available concerning trading prices and volume, and fewer broker-dealers would be willing to execute trades with respect to such securities. A suspension or delisting would likely decrease the attractiveness of our common stock to investors and cause the trading volume of our common stock to decline, which could result in a further decline in the market price of our common stock.

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

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the granting of stock awards and the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under ~~our~~any authorized share repurchase program. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the ~~three months ended September 30, 2016:~~specified periods:

Period
Total Number
of Shares
Purchased (1)

Average Price
Paid per Share

Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs (2)

Approximate Dollar Value of Shares that MayYet be
Purchased Under the
Plans or Programs
July 1 - July 31, 2016 1,639
$ 12.40
—

August 1 - August 31, 2016 5,730
10.23
—

September1 - September 30, 2016 —
—
—

7,369
$ 10.74
—
$ 92,928,632



Period		Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that MayYet be Purchased Under the Plans or Programs
January 1 - January 31, 2017	(Predecessor)	9,568	$	6.63	—
February 1 - February 28, 2017	(Predecessor)	6,749	6.76		—
March 1 - March 31, 2017	(Successor)	—	—		—
						$	—


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


~~(2)~~	~~There were no repurchases of our common stock under our share repurchase program during the three months ended September 30, 2016.~~

ITEM 6. EXHIBITS

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~~Item 6. Exhibits~~



Exhibit Number			Description
2.1			Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on Form 8-K filed on February 15, 2017 (File No. 001-12074)).
3.1			Amended and Restated Certificate of Incorporation of ~~the Registrant, as amended~~Stone Energy Corporation (incorporated by reference to Exhibit 3.1 toof the Registrant's ~~Quarterly Report~~registration statement on Form ~~10-Q for the quarter ended June 30, 2016~~8-A filed on February 28, 2017 (File No. 001-12074)).
3.2			Second Amended &and Restated Bylaws of Stone Energy Corporation ~~dated December 19, 2013~~ (incorporated by reference to Exhibit 3.2 toof the Registrant’s ~~Annual Report~~registration statement on Form ~~10-K for the year ended December 31, 2013~~8-A filed on February 28, 2017 (File No. 001-12074)).
4.1			Form of Global Warrant Certificate (included in Exhibit 10.4).
4.2			Form of 2022 Second Lien Note (included in Exhibit 10.2).
10.1			~~Restructuring Support~~Fifth Amended and Restated Credit Agreement, dated ~~October 20, 2016, by and~~as of February 28, 2017, among Stone Energy Corporation, ~~and its subsidiaries~~as borrower, the lenders party thereto and ~~the Undersigned Creditor Parties~~Bank of America, N.A. as administrative agent and issuing bank (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
10.2			Indenture related to the 2022 Second Lien Notes, dated as of February 28, 2017, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (including form of 7.50% Senior Secured Notes due 2022) (incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K filed on ~~October 21, 2016~~March 1, 2017 (File No. 001-12074)).
~~10.2~~10.3			Intercreditor Agreement, dated as of February 28, 2017, among Stone Energy Corporation, Bank of America, N.A., as first lien administrative agent, The Bank of New York Mellon Trust Company, N.A., as second lien collateral agent, and The Bank of New York Mellon Trust Company, N.A., as the 2022 Second Lien Notes trustee (incorporate by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
10.4			Warrant Agreement, dated as of February 28, 2017, among Stone Energy Corporation and Computershare Inc. and Computershare Trust Company, N.A., collectively, as warrant agent (incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
10.5			Registration Rights Agreement, dated as of February 28, 2017, among Stone Energy Corporation and the holders party thereto (incorporated by reference to Exhibit 10.1 of the Registrant's registration statement on Form 8-A filed on February 28, 2017 (File No. 001-12074)).
10.6			Form of Indemnification Agreement between Stone Energy Corporation and the directors and executive officers of Stone Energy Corporation (incorporated by reference to Exhibit 10.6 of the Registrant's Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
†10.7			Stone Energy Corporation 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 of the Registrant's Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).

Table of Contents



10.8			Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and ~~TH Exploration III, LLC~~EQT Production Company as buyer, and EQT Corporation as buyer parent, dated ~~October 20, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 21, 2016 (File No. 001-12074)).~~
~~10.3~~			~~First Amendment to Restructuring Support Agreement, dated November 4, 2016, by and among the Stone Parties and the Consenting Noteholders~~February 9, 2017 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed ~~on November 4, 2016~~February 10, 2017 (File No. 001-12074)).
*10.4†10.9			~~Letter Agreement dated August 10, 2016 between~~ Form of Director Restricted Stock Unit (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed on March 6, 2017 (File No. 001-12074)).
†10.10			Stone Energy Corporation ~~and Richard L. Toothman, Jr.~~Directors Deferred Compensation Plan, dated as of March 1, 2017 (incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K filed on March 6, 2017 (File No. 001-12074)).
*31.1			Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2			Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1			Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
99.1			Order Approving Debtors' Disclosure Statement and Confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, as entered by the Bankruptcy Court on February 15, 2017 (incorporated by reference to Exhibit 99.1 of the Registrant's Current Report on Form 8-K filed on February 15, 2017 (File No. 001-12074)).
*101.INS			XBRL Instance Document
*101.SCH			XBRL Taxonomy Extension Schema Document
*101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF			XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB			XBRL Taxonomy Extension Label Linkbase Document
*101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document



*		Filed or furnished herewith.


#		Not considered to be ~~“filed”~~"filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
†		Identifies management contracts and compensatory plans or arrangements.

5344

Table of Contents

SIGNATURES

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



		STONE ENERGY CORPORATION

Date:	~~November 7, 2016~~May 8, 2017	By:	/s/ Kenneth H. Beer
			Kenneth H. Beer
			Executive Vice President and Chief Financial Officer
			(On behalf of the Registrant and as
			Principal Financial Officer)

5445

Table of Contents

EXHIBIT INDEX



Exhibit Number			Description
2.1			Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on Form 8-K filed on February 15, 2017 (File No. 001-12074)).
3.1			Amended and Restated Certificate of Incorporation of ~~the Registrant, as amended~~Stone Energy Corporation (incorporated by reference to Exhibit 3.1 toof the Registrant's ~~Quarterly Report~~registration statement on Form ~~10-Q for the quarter ended June 30, 2016~~8-A filed on February 28, 2017 (File No. 001-12074)).
3.2			Second Amended &and Restated Bylaws of Stone Energy Corporation ~~dated December 19, 2013~~ (incorporated by reference to Exhibit 3.2 toof the Registrant’s ~~Annual Report~~registration statement on Form ~~10-K for the year ended December 31, 2013~~8-A filed on February 28, 2017 (File No. 001-12074)).
4.1			Form of Global Warrant Certificate (included in Exhibit 10.4).
4.2			Form of 2022 Second Lien Note (included in Exhibit 10.2).
10.1			~~Restructuring Support~~Fifth Amended and Restated Credit Agreement, dated ~~October 20, 2016, by and~~as of February 28, 2017, among Stone Energy Corporation, ~~and its subsidiaries~~as borrower, the lenders party thereto and ~~the Undersigned Creditor Parties~~Bank of America, N.A. as administrative agent and issuing bank (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
10.2			Indenture related to the 2022 Second Lien Notes, dated as of February 28, 2017, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (including form of 7.50% Senior Secured Notes due 2022) (incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K filed on ~~October 21, 2016~~March 1, 2017 (File No. 001-12074)).
~~10.2~~10.3			Intercreditor Agreement, dated as of February 28, 2017, among Stone Energy Corporation, Bank of America, N.A., as first lien administrative agent, The Bank of New York Mellon Trust Company, N.A., as second lien collateral agent, and The Bank of New York Mellon Trust Company, N.A., as the 2022 Second Lien Notes trustee (incorporate by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
10.4			Warrant Agreement, dated as of February 28, 2017, among Stone Energy Corporation and Computershare Inc. and Computershare Trust Company, N.A., collectively, as warrant agent (incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
10.5			Registration Rights Agreement, dated as of February 28, 2017, among Stone Energy Corporation and the holders party thereto (incorporated by reference to Exhibit 10.1 of the Registrant's registration statement on Form 8-A filed on February 28, 2017 (File No. 001-12074)).
10.6			Form of Indemnification Agreement between Stone Energy Corporation and the directors and executive officers of Stone Energy Corporation (incorporated by reference to Exhibit 10.6 of the Registrant's Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
†10.7			Stone Energy Corporation 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 of the Registrant's Current Report on Form 8-K filed on March 1, 2017 (File No. 001-12074)).
10.8			Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and ~~TH Exploration III, LLC~~EQT Production Company as buyer, and EQT Corporation as buyer parent, dated ~~October 20, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 21, 2016 (File No. 001-12074)).~~
~~10.3~~			~~First Amendment to Restructuring Support Agreement, dated November 4, 2016, by and among the Stone Parties and the Consenting Noteholders~~February 9, 2017 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed ~~on November 4, 2016~~February 10, 2017 (File No. 001-12074)).
*10.4†10.9			~~Letter Agreement dated August 10, 2016 between~~ Form of Director Restricted Stock Unit (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed on March 6, 2017 (File No. 001-12074)).
†10.10			Stone Energy Corporation ~~and Richard L. Toothman, Jr.~~Directors Deferred Compensation Plan, dated as of March 1, 2017 (incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K filed on March 6, 2017 (File No. 001-12074)).
*31.1			Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2			Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1			Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
99.1			Order Approving Debtors' Disclosure Statement and Confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, as entered by the Bankruptcy Court on February 15, 2017 (incorporated by reference to Exhibit 99.1 of the Registrant's Current Report on Form 8-K filed on February 15, 2017 (File No. 001-12074)).
*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

Table of Contents



*101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document



*		Filed or furnished herewith.


#		Not considered to be ~~“filed”~~"filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
†		Identifies management contracts and compensatory plans or arrangements.

5547



	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



Fair Value of Derivatives Qualifying as Hedging Instruments at
September 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	$	6.3	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	—		Long-term liabilities: Fair value of derivative contracts	—
		$	6.3		$	—

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		$	—



	Nine Months Ended September 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	(15.1		)
Accretion expense	30.1
Asset retirement obligations as of the end of the period, including current portion	$	243.0



	Fair Value Measurements at
	September 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)	$	8.8	$	8.8	$	—	$	—
Derivative contracts	6.3		—		6.3		—
Total	$	15.1	$	8.8	$	6.3	$	—



	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 September 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 September 30, 2016	$	—



	Cash Flow Hedges
Three Months Ended September 30, 2016
Beginning balance, net of tax	$	7.4
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	2.3
Income tax effect	(0.8		)
Net of tax	1.5
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	7.7
Income tax effect	(2.7		)
Net of tax	5.0
Other comprehensive loss, net of tax	(3.5		)
Ending balance, net of tax	$	3.9



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	152,384		$	30,015		$	—		$	—		$	182,399
Accounts receivable	17,336			40,736			883			(14,892		)	44,063
Fair value of derivative contracts	—			6,261			—			—			6,261
Current income tax receivable	19,863			—			—			—			19,863
Other current assets	11,176			—			—			—			11,176
Total current assets	200,759			77,012			883			(14,892		)	263,762
Oil and gas properties, full cost method:
Proved	1,932,435			7,586,930			45,196			—			9,564,561
Less: accumulated DD&A	(1,932,640		)	(7,076,233		)	(45,196		)	—			(9,054,069		)
Net proved oil and gas properties	(205		)	510,697			—			—			510,492
Unevaluated	261,101			143,125			—			—			404,226
Other property and equipment, net	27,227			—			—			—			27,227
Other assets, net	28,852			948			—			—			29,800
Investment in subsidiary	480,971			—			—			(480,971		)	—
Total assets	$	998,705		$	731,782		$	883		$	(495,863	)	$	1,235,507
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	35,189		$	8,963		$	—		$	(14,893	)	$	29,259
Undistributed oil and gas proceeds	6,535			904			—			—			7,439
Accrued interest	22,917			—			—			—			22,917
Asset retirement obligations	—			60,223			—			—			60,223
Current portion of long-term debt	292,795			—			—			—			292,795
Other current liabilities	10,778			125			—			—			10,903
Total current liabilities	368,214			70,215			—			(14,893		)	423,536
Long-term debt	1,122,945			—			—			—			1,122,945
Asset retirement obligations	1,336			181,480			—			—			182,816
Other long-term liabilities	25,871			—			—			—			25,871
Total liabilities	1,518,366			251,695			—			(14,893		)	1,755,168
Commitments and contingencies
Stockholders’ equity:
Common stock	56			—			—			—			56
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,657,028			1,344,577			109,079			(1,453,656		)	1,657,028
Accumulated deficit	(2,179,803		)	(868,408		)	(108,196		)	976,604			(2,179,803		)
Accumulated other comprehensive income	3,918			3,918			—			(3,918		)	3,918
Total stockholders’ equity	(519,661		)	480,087			883			(480,970		)	(519,661		)
Total liabilities and stockholders’ equity	$	998,705		$	731,782		$	883		$	(495,863	)	$	1,235,507



	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net loss	$	(474,180	)	$	(243,584	)	$	(12,890	)	$	256,474		$	(474,180	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	45,452			121,255			—			—			166,707
Write-down of oil and gas properties	15,859			268,128			350			—			284,337
Accretion expense	174			29,973			—			—			30,147
Deferred income tax provision	—			10,947			—			—			10,947
Settlement of asset retirement obligations	(78		)	(14,129		)	(899		)	—			(15,106		)
Non-cash stock compensation expense	6,407			—			—			—			6,407
Non-cash derivative expense	—			1,261			—			—			1,261
Non-cash interest expense	14,278			—			—			—			14,278
Other non-cash expense	—			—			6,081			—			6,081
Change in current income taxes	21,584			—			—			—			21,584
Non-cash loss from investment in subsidiaries	250,029			—			6,445			(256,474		)	—
Change in intercompany receivables/payables	(1,658		)	1,658			—			—			—
(Increase) decrease in accounts receivable	7,966			(3,116		)	(882		)	—			3,968
(Increase) decrease in other current assets	(4,459		)	—			33			—			(4,426		)
Increase (decrease) in accounts payable	7,385			(4,168		)	—			—			3,217
Decrease in other current liabilities	(13,924		)	(298		)	—			—			(14,222		)
Other	(7,389		)	(718		)	—			—			(8,107		)
Net cash (used in) provided by operating activities	(132,554		)	167,209			(1,762		)	—			32,893
Cash flows from investing activities:
Investment in oil and gas properties	(63,075		)	(137,196		)	(351		)	—			(200,622		)
Investment in fixed and other assets	(1,231		)	—			—			—			(1,231		)
Change in restricted funds	—			—			1,046			—			1,046
Investment in subsidiaries	—			—			716			(716		)	—
Net cash (used in) provided by investing activities	(64,306		)	(137,196		)	1,411			(716		)	(200,807		)
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	(285		)	—			—			—			(285		)
Deferred financing costs	(900		)	—			—			—			(900		)
Equity proceeds from parent	—			—			(716		)	716			—
Net payments for share-based compensation	(752		)	—			—			—			(752		)
Net cash provided by (used in) financing activities	339,563			—			(716		)	716			339,563
Effect of exchange rate changes on cash	—			—			(9		)	—			(9		)
Net change in cash and cash equivalents	142,703			30,013			(1,076		)	—			171,640
Cash and cash equivalents, beginning of period	9,681			2			1,076			—			10,759
Cash and cash equivalents, end of period	$	152,384		$	30,015		$	—		$	—		$	182,399