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~~March 3031, ~~2017~~2018



¨	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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	¨	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

Table of Contents

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 May 7, 2018, there were 19,998,701 shares of the registrant’s common stock, par value $.01 per share, outstanding.

Table of Contents

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheet as of September 30, 2017 and December 31, 2016	1
	Condensed Consolidated Balance Sheet as of March 31, 2018 and December 31, 2017	1
	Condensed Consolidated Statement of Operations for the Three Months Ended September 30, 2017 and 2016	2
	Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2018, the Period March 1, 2017 through March 31, 2017 and the Period January 1, 2017 through February 28, 2017	2
	Condensed Consolidated Statement of Operations for the Period March 1, 2017 through September 30, 2017, the Period January 1, 2017 through February 28, 2017 and the Nine Months Ended September 30, 2016	3
	Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2018, the Period March 1, 2017 through December 31, 2017 and the Period January 1, 2017 through February 28, 2017	3
	Condensed Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended September 30, 2017 and 2016	4
	Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2018, the Period March 1, 2017 through March 31, 2017 and the Period January 1, 2017 through February 28, 2017	4
	Condensed Consolidated Statement of Comprehensive Income (Loss) for the Period March 1, 2017 through September 30, 2017, the Period January 1, 2017 through February 28, 2017 and the Nine Months Ended September 30, 2016	5
	Notes to Condensed Consolidated Financial Statements	5
	Condensed Consolidated Statement of Changes in Stockholders' Equity for the Period March 1, 2017 through September 30, 2017, the Period January 1, 2017 through February 28, 2017 and the Year Ended December 31, 2016	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
	Condensed Consolidated Statement of Cash Flows for the Period March 1, 2017 through September 30, 2017, the Period January 1, 2017 through February 28, 2017 and the Nine Months Ended September 30, 2016	7
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
	Notes to Condensed Consolidated Financial Statements	8
Item 4.	Controls and Procedures	33
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	47
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	4834
Item 1A.	Risk Factors	4834
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4835
Item 6.	Exhibits	4935
	Signatures	5037

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)

	Successor				~~Predecessor~~
	September 30,2017				December 31,2016
	March 31,2018			December 31,2017
Assets	(Unaudited)				(Note 1)
	(Unaudited)			(Note 1)
Current assets:
Assets
Cash and cash equivalents	$	245,714			$	190,581
Current assets:
Restricted cash	37,684				—
Cash and cash equivalents	$	277,842		$	263,495
Accounts receivable	35,670				48,464
Restricted cash	—			18,742
Fair value of derivative contracts	2,565				—
Accounts receivable	36,378			39,258
Current income tax receivable	27,672				26,086
Fair value of derivative contracts	417			879
Other current assets	9,295				10,151
Current income tax receivable	16,212			36,260
Total current assets	358,600				275,282
Other current assets	6,901			7,138
Oil and gas properties, full cost method of accounting:
Total current assets	337,750			365,772
Proved	714,515				9,616,236
Oil and gas properties, full cost method of accounting:
Less: accumulated depreciation, depletion and amortization	(330,921		)		(9,178,442		)
Proved	713,304			713,157
Net proved oil and gas properties	383,594				437,794
Less: accumulated depreciation, depletion and amortization	(374,063		)	(353,462		)
Unevaluated	102,283				373,720
Net proved oil and gas properties	339,241			359,695
Other property and equipment, net	18,433				26,213
Unevaluated	118,365			102,187
Fair value of derivative contracts	1,040				—
Other property and equipment, net	16,544			17,275
Other assets, net	1814,~~252~~066			13,844	~~26,474~~
Total assets	$	~~882~~825,~~202~~966		$	$858,773	~~1,139,483~~
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	3320,~~120~~088		$	$54,226	~~19,981~~
Undistributed oil and gas proceeds	54,~~439~~283			5,142	~~15,073~~
Accrued interest	106,~~244~~038			1,685	~~809~~
Fair value of derivative contracts	~~368~~13,147			8,969	—
Asset retirement obligations	8456,~~654~~428			79,300	~~88,000~~
Current portion of long-term debt	~~421~~430			425	~~408~~
Other current liabilities	2813,~~503~~552			22,579	~~18,602~~
Total current liabilities	~~162~~113,~~749~~966			172,326	~~142,873~~
Long-term debt	235,~~567~~394			235,502	~~352,376~~
Asset retirement obligations	~~182~~140,~~956~~226			133,801	~~154,019~~
Fair value of derivative contracts	744,564			3,085	—
Other long-term liabilities	105,~~110~~743			5,891	~~17,315~~
Total liabilities not subject to compromise	591,456				666,583
Total liabilities	499,893			550,605
Liabilities subject to compromise	—				1,110,182
Commitments and contingencies
Total liabilities	591,456				1,776,765
Stockholders’ equity:
Commitments and contingencies
Common stock ($.01 par value; authorized 60,000,000 shares; issued 19,998,701 and 19,998,019 shares, respectively)	200			200
Stockholders’ equity:
Additional paid-in capital	555,940			555,607
Predecessor common stock ($.01 par value; authorized 30,000,000 shares; issued 5,610,020 shares)	—				56
Accumulated deficit	(230,067		)	(247,639		)
Predecessor treasury stock (1,658 shares, at cost)	—				(860		)
Total stockholders’ equity	326,073			308,168
Predecessor additional paid-in capital	—				1,659,731
Total liabilities and stockholders’ equity	$	825,966		$	858,773
Successor common stock ($.01 par value; authorized 60,000,000 shares; issued 19,998,019 shares)	200				—
Successor additional paid-in capital	555,323				—
Accumulated deficit	(264,777		)		(2,296,209		)
Total stockholders’ equity	290,746				(637,282		)
Total liabilities and stockholders’ equity	$	882,202			$	1,139,483

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

Table of Contents

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Successor				~~Predecessor~~			Predecessor
	Three Months EndedSeptember 30, 2017				Three Months EndedSeptember 30, 2016
	Three Months EndedMarch 31, 2018			Period fromMarch 1, 2017throughMarch 31, 2017				Period fromJanuary 1, 2017throughFebruary 28, 2017
Operating revenue:
Oil production	$	6173,~~841~~261		$	$20,027	~~71,116~~		$	45,837
Natural gas production	54,~~451~~900			2,210	~~15,601~~			13,476
Natural gas liquids production	23,~~473~~188			777	~~6,666~~			8,706
Other operational income	~~9,760~~27			149	~~1,044~~			903
Total operating revenue	79,525				94,427
Derivative income, net	—			2,646				—
Operating expenses:
Total operating revenue	81,376			25,809				68,922
Lease operating expenses	11,778				16,976
Operating expenses:
Transportation, processing and gathering expenses	1,076				10,633
Lease operating expenses	14,380			4,740				8,820
Production taxes	188				835
Transportation, processing and gathering expenses	783			144				6,933
Depreciation, depletion and amortization	27,553				58,918
Production taxes	(2,201		)	65				682
Write-down of oil and gas properties	—				36,484
Depreciation, depletion and amortization	21,333			15,847				37,429
Accretion expense	8,095				10,082
Write-down of oil and gas properties	—			256,435				—
Salaries, general and administrative expenses	15,887				15,425
Accretion expense	4,287			2,901				5,447
Incentive compensation expense	4,646				2,160
Salaries, general and administrative expenses	12,556			3,322				9,629
Restructuring fees	129				5,784
Incentive compensation expense	387			—				2,008
Other operational expenses	703				9,059
Restructuring fees	—			288				—
Derivative expense, net	6,685				199
Other operational expenses	179			661				530
Total operating expenses	76,740				166,555
Derivative expense, net	9,548			—				1,778
Gain (loss) on Appalachia Properties divestiture	(132		)		—
Total operating expenses	61,252			284,403				73,256
Income (loss) from operations	2,653				(72,128		)
Gain on Appalachia Properties divestiture	—			—				213,453
Other (income) expense:
Income (loss) from operations	20,124			(258,594		)		209,119
Interest expense	3,529				16,924
Other (income) expense:
Interest income	(366		)		(58		)
Interest expense	3,537			1,190				—
Other income	(276		)		(272		)
Interest income	(1,539		)	(40		)		(45		)
Other expense	47				16
Other income	(203		)	(131		)		(315		)
Total other expense	2,934				16,610
Other expense	21			—				13,336
Loss before income taxes	(281		)		(88,738		)
Reorganization items, net	—			—				(437,744		)
Provision (benefit) for income taxes:
Total other (income) expense	1,816			1,019				(424,768		)
Current	(1,578		)		(991		)
Income (loss) before income taxes	18,308			(259,613		)		633,887
Deferred	—				1,888
Provision (benefit) for income taxes:
Total income taxes	(1,578		)		897
Current	—			—				3,570
Net income (loss)	$	1,297			$	(89,635	)
Total income taxes	—			—				3,570
Basic income (loss) per share	$	0.06			$	(16.01	)
Net income (loss)	$	18,308		$	(259,613	)		$	630,317
Diluted income (loss) per share	$	0.06			$	(16.01	)
Basic income (loss) per share	$	0.91		$	(12.98	)		$	110.99
Average shares outstanding	19,997				5,600
Diluted income (loss) per share	$	0.91		$	(12.98	)		$	110.99
Average shares outstanding assuming dilution	19,997				5,600
Average shares outstanding	19,998			19,997				5,634
Average shares outstanding assuming dilution	19,998			19,997				5,634

The accompanying notes are an integral part of this statement.

Table of Contents

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Successor			Predecessor
	Period fromMarch 1, 2017throughSeptember 30, 2017			Period fromJanuary 1, 2017throughFebruary 28, 2017			Nine Months EndedSeptember 30, 2016
Operating revenue:
Oil production	$	143,556		$	45,837		$	204,102
Natural gas production	14,201			13,476			43,327
Natural gas liquids production	6,264			8,706			15,119
Other operational income	9,936			903			1,737
Derivative income, net	1,414			—			—
Total operating revenue	175,371			68,922			264,285
Operating expenses:
Lease operating expenses	33,154			8,820			55,349
Transportation, processing and gathering expenses	3,045			6,933			18,657
Production taxes	446			682			1,894
Depreciation, depletion and amortization	76,553			37,429			166,707
Write-down of oil and gas properties	256,435			—			284,337
Accretion expense	19,698			5,447			30,147
Salaries, general and administrative expenses	37,718			9,629			48,193
Incentive compensation expense	4,646			2,008			11,809
Restructuring fees	739			—			16,173
Other operational expenses	3,292			530			49,266
Derivative expense, net	—			1,778			687
Total operating expenses	435,726			73,256			683,219
Gain (loss) on Appalachia Properties divestiture	(105		)	213,453			—
Income (loss) from operations	(260,460		)	209,119			(418,934		)
Other (income) expense:
Interest expense	8,320			—			49,764
Interest income	(575		)	(45		)	(474		)
Other income	(719		)	(315		)	(840		)
Other expense	861			13,336			27
Reorganization items, net	—			(437,744		)	—
Total other (income) expense	7,887			(424,768		)	48,477
Income (loss) before income taxes	(268,347		)	633,887			(467,411		)
Provision (benefit) for income taxes:
Current	(3,570		)	3,570			(4,178		)
Deferred	—			—			10,947
Total income taxes	(3,570		)	3,570			6,769
Net income (loss)	$	(264,777	)	$	630,317		$	(474,180	)
Basic income (loss) per share	$	(13.24	)	$	110.99		$	(84.90	)
Diluted income (loss) per share	$	(13.24	)	$	110.99		$	(84.90	)
Average shares outstanding	19,997			5,634			5,585
Average shares outstanding assuming dilution	19,997			5,634			5,585

The accompanying notes are an integral part of this statement.

Table of Contents

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Successor		Predecessor
	Three Months EndedSeptember 30, 2017		Three Months EndedSeptember 30, 2016
Net income (loss)	$	1,297	$	(89,635	)
Other comprehensive loss, net of tax effect:
Derivatives	—		(3,467		)
Comprehensive income (loss)	$	1,297	$	(93,102	)

The accompanying notes are an integral part of this statement.

Table of Contents

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Successor			Predecessor
	Period fromMarch 1, 2017throughSeptember 30, 2017			Period fromJanuary 1, 2017throughFebruary 28, 2017		Nine Months EndedSeptember 30, 2016
Net income (loss)	$	(264,777	)	$	630,317	$	(474,180	)
Other comprehensive income (loss), net of tax effect:
Derivatives	—			—		(20,107		)
Foreign currency translation	—			—		6,073
Comprehensive income (loss)	$	(264,777	)	$	630,317	$	(488,214	)

The accompanying notes are an integral part of this statement.

Table of Contents

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)

	CommonStock			TreasuryStock			AdditionalPaid-InCapital			AccumulatedDeficit			~~AccumulatedOtherComprehensiveIncome (Loss)~~TotalStockholders’Equity			~~TotalStockholders’Equity~~
Balance, December 31, 2015 (Predecessor)	$	55		$	(860	)	$	1,648,687		$	(1,705,623	)	$	17,952		$	(39,789	)
Balance, December 31, 2016 (Predecessor)	$	56		$	(860	)	$	1,659,731		$	(2,296,209	)	$	(637,282	)
Net loss	—			—			—			(590,586		)	—			(590,586		)
Net income	—			—			—			630,317			630,317
Adjustment for fair value accounting of derivatives, net of tax	—			—			—			—			(24,025		)	(24,025		)
Lapsing of forfeiture restrictions of restricted stock and granting of stock awards	—			—			(172		)	—			(172		)
Adjustment for foreign currency translation, net of tax	—			—			—			—			6,073			6,073
Amortization of stock compensation expense	—			—			3,527			—			3,527
Exercise of stock options, vesting of restricted stock and granting of stock awards	1			—			(732		)	—			—			(731		)
Balance, February 28, 2017 (Predecessor)	56			(860		)	1,663,086			(1,665,892		)	(3,610		)
Amortization of stock compensation expense	—			—			11,776			—			—			11,776
Cancellation of Predecessor equity	(56		)	860			(1,663,086		)	1,665,892			3,610
Balance, December 31, 2016 (Predecessor)	56			(860		)	1,659,731			(2,296,209		)	—			(637,282		)
Balance, February 28, 2017 (Predecessor)	—			—			—			—			—
Net income	—			—			—			630,317			—			630,317
Issuance of Successor common stock and warrants	200			—			554,537			—			554,737
Exercise of stock options, vesting of restricted stock and granting of stock awards	—			—			(172		)	—			—			(172		)
Balance, February 28, 2017 (Successor)	200			—			554,537			—			554,737
Amortization of stock compensation expense	—			—			3,527			—			—			3,527
Net loss	—			—			—			(247,639		)	(247,639		)
Balance, February 28, 2017 (Predecessor)	56			(860		)	1,663,086			(1,665,892		)	—			(3,610		)
Lapsing of forfeiture restrictions of restricted stock	—			—			(19		)	—			(19		)
Cancellation of Predecessor equity	(56		)	860			(1,663,086		)	1,665,892			—			3,610
Amortization of stock compensation expense	—			—			1,272			—			1,272
Balance, February 28, 2017 (Predecessor)	—			—			—			—			—			—
Stock issuance costs - Talos combination	—			—			(183		)	—			(183		)
Issuance of Successor common stock and warrants	200			—			554,428			—			—			554,628
Balance, December 31, 2017 (Successor)	200			—			555,607			(247,639		)	308,168
Balance, February 28, 2017 (Successor)	200			—			554,428			—			—			554,628
Cumulative effect adjustment (see Note 13)	—			—			—			(736		)	(736		)
Net loss	—			—			—			(264,777		)	—			(264,777		)
Net income	—			—			—			18,308			18,308
Exercise of stock options, vesting of restricted stock and granting of stock awards	—			—			(19		)	—			—			(19		)
Lapsing of forfeiture restrictions of restricted stock	—			—			(15		)	—			(15		)
Amortization of stock compensation expense	—			—			~~914~~348			—			—348			~~914~~
Balance, September 30, 2017 (Successor)	$	200		$	—		$	555,323		$	(264,777	)	$	—		$	290,746
Balance, March 31, 2018 (Successor)	$	200		$	—		$	555,940		$	(230,067	)	$	326,073

The accompanying notes are an integral part of this statement.

Table of Contents

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)

	Successor				~~Predecessor~~			Predecessor
	Period fromMarch 1, 2017throughSeptember 30, 2017				Period fromJanuary 1, 2017throughFebruary 28, 2017			Nine Months EndedSeptember 30, 2016
	Three Months EndedMarch 31, 2018			Period fromMarch 1, 2017throughMarch 31, 2017				Period fromJanuary 1, 2017throughFebruary 28, 2017
Cash flows from operating activities:
Net income (loss)	$	~~(264~~18,~~777~~308	)	$	$(259,613	~~630,317~~)		$	~~(474~~630,~~180~~317	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	7621,~~553~~333			15,847	~~37,429~~			~~166~~37,~~707~~429
Write-down of oil and gas properties	~~256,435~~—			256,435	—			~~284,337~~—
Accretion expense	194,~~698~~287			2,901	~~5,447~~			305,~~147~~447
Deferred income tax provision	—				—			10,947
Gain on sale of oil and gas properties	—			—				(213,453		)
(Gain) loss on sale of oil and gas properties	105				(213,453		)	—
Settlement of asset retirement obligations	(20,734		)	(17,600		)		(3,641		)
Settlement of asset retirement obligations	(53,129		)		(3,641		)	(15,106		)
Non-cash stock compensation expense	348			17				2,645
Non-cash stock compensation expense	893				2,645			6,407
Non-cash derivative (income) expense	6,119			(2,484		)		1,778
Non-cash derivative expense	1,210				1,778			1,261
Non-cash interest expense	1			—				—
Non-cash interest expense	3				—			14,278
Non-cash reorganization items	—			—				(458,677		)
Non-cash reorganization items	—				(458,677		)	—
Other non-cash expense	22			—				172
Other non-cash expense	877				172			6,081
Change in current income taxes	20,049			—				3,570
Change in current income taxes	(5,156		)		3,570			21,584
Decrease in accounts receivable	2,144			6,728				6,354
Decrease in accounts receivable	6,059				6,354			3,968
(Increase) decrease in other current assets	237			964				(2,274		)
(Increase) decrease in other current assets	2,382				(2,274		)	(4,426		)
Increase (decrease) in accounts payable	(13,701		)	3,015				(4,652		)
Increase (decrease) in accounts payable	10,662				(4,652		)	3,217
Increase (decrease) in other current liabilities	(5,534		)	1,672				(9,653		)
Increase (decrease) in other current liabilities	17,944				(9,653		)	(14,222		)
Investment in derivative contracts	—			(2,140		)		(3,736		)
Investment in derivative contracts	(2,416		)		(3,736		)	—
Other	(393		)	4,904				2,490
Other	3,054				2,490			(8,107		)
Net cash provided by (used in) operating activities	32,486			10,646				(5,884		)
Net cash provided by (used in) operating activities	70,397				(5,884		)	32,893
Cash flows from investing activities:
Investment in oil and gas properties	(4237,~~837~~081		)	(5,584	~~(8,754~~	)	)	(~~200~~8,~~622~~754		)
Proceeds from sale of oil and gas properties, net of expenses	~~17,777~~320			10,770	~~505,383~~			—505,383
Investment in fixed and other assets	~~(158~~—		)	(2	~~(61~~	)	)	(~~1,231~~61		)
Change in restricted funds	37,863				(75,547		)	1,046
Net cash provided by (used in) investing activities	(36,761		)	5,184				496,568
Net cash provided by (used in) investing activities	12,645				421,021			(200,807		)
Cash flows from financing activities:
Proceeds from bank borrowings	—				—			477,000
Repayments of bank borrowings	—			—				(341,500		)
Repayments of bank borrowings	—				(341,500		)	(135,500		)
Repayments of building loan	(105		)	(36		)		(24		)
Repayments of building loan	(275		)		(24		)	(285		)
Cash payment to noteholders	—			—				(100,000		)
Cash payment to noteholders	—				(100,000		)	—
Debt issuance costs	—			—				(1,055		)
Debt issuance costs	—				(1,055		)	(900		)
Net payments for share-based compensation	(15		)	—				(173		)
Net payments for share-based compensation	(19		)		(173		)	(752		)
Net cash used in financing activities	(120		)	(36		)		(442,752		)
Net cash provided by (used in) financing activities	(294		)		(442,752		)	339,563
Net change in cash, cash equivalents and restricted cash	(4,395		)	15,794				47,932
Effect of exchange rate changes on cash	—				—			(9		)
Cash, cash equivalents and restricted cash, beginning of period	282,237			238,513				190,581
Net change in cash and cash equivalents	82,748				(27,615		)	171,640
Cash, cash equivalents and restricted cash, end of period	$	277,842		$	254,307			$	238,513
Cash and cash equivalents, beginning of period	162,966				190,581			10,759
Cash and cash equivalents, end of period	$	245,714			$	162,966		$	182,399

The accompanying notes are an integral part of this statement.

Table of Contents

STONE ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – FINANCIAL STATEMENT PRESENTATION

Interim Financial Statements

The condensed consolidated financial statements of Stone Energy Corporation (“Stone” or the “Company”) and its subsidiaries as of ~~September~~March 3031, ~~2017~~2018 (Successor) and for the three ~~month~~months ~~period~~ ended ~~September~~March 3031, ~~2017~~2018 (Successor), and the periods from March 1, 2017 through ~~September~~March 3031, 2017 (Successor), and January 1, 2017 through February 28, 2017 (Predecessor) ~~and the three and nine months ended September 30, 2016 (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, ~~2016~~2017 (~~Predecessor~~Successor) 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, ~~2016~~2017 (our “~~2016~~2017 Annual Report on Form 10-K”). The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations, contained in our ~~2016~~2017 Annual Report on Form 10-K, although, 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 ~~period~~three ~~from~~months ended March 131, ~~2017~~2018 ~~through September 30, 2017~~ (Successor) are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation.

~~Emergence~~Pending ~~from~~Combination ~~Voluntary~~with ~~Reorganization Under Chapter 11 Proceedings~~Talos

On ~~December~~November 1421, ~~2016~~2017, ~~the~~Stone ~~Company~~ and certain of its subsidiaries ~~Stone~~entered ~~Energy~~into ~~Offshore,~~a ~~L.L.C.~~series ~~(“Stone~~of ~~Offshore”)~~related ~~and~~agreements ~~Stone~~pertaining ~~Energy~~to ~~Holding,~~a ~~L.L.C.~~business ~~(together~~combination with ~~the~~Talos ~~Company,~~Energy ~~the~~LLC ~~“Debtors”) filed voluntary petitions~~ (~~the~~ “~~Bankruptcy~~Talos ~~Petitions~~Energy”) inand ~~the~~its ~~United~~indirect ~~States~~wholly ~~Bankruptcy~~owned ~~Court~~subsidiary ~~for~~Talos ~~the~~Production ~~Southern~~LLC ~~District of Texas, Houston Division~~ (~~the~~ “~~Bankruptcy~~Talos ~~Court~~Production”) ~~seeking~~and, ~~relief~~together ~~under~~with ~~the~~Talos ~~provisions~~Energy, ~~of Chapter 11 of Title 11 (~~“~~Chapter 11~~Talos”). ofTalos ~~the~~Energy ~~United~~is ~~States~~controlled ~~Bankruptcy~~indirectly ~~Code~~by ~~(the~~entities ~~“Bankruptcy~~controlled ~~Code”).~~by OnApollo ~~February~~Management 15VII, ~~2017,~~L.P. ~~the Bankruptcy Court entered an order~~ (~~the~~ “~~Confirmation~~Apollo ~~Order~~VII”) ~~confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates~~, ~~dated~~Apollo ~~December~~Commodities 28Management, ~~2016 (the “Plan”)~~L.P., aswith ~~modified~~respect byto ~~the~~Series ~~Confirmation~~I ~~Order,~~(together ~~and~~with onApollo ~~February 28~~VII, ~~2017, the Plan became effective (the~~ “~~Effective~~Apollo ~~Date~~Management”) and ~~the~~Riverstone ~~Debtors~~Energy ~~emerged~~Partners ~~from bankruptcy~~V, ~~with~~L.P. ~~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~~(“Riverstone”).

~~Upon~~Stone, ~~emergence~~Sailfish ~~from~~Energy ~~bankruptcy~~Holdings Corporation (“New Talos”), ~~the~~a ~~Company~~direct ~~adopted~~wholly ~~fresh~~owned ~~start~~subsidiary ~~accounting~~of inStone, ~~accordance~~and ~~with~~Sailfish ~~the~~Merger ~~provisions~~Sub Corporation, a direct wholly owned subsidiary of ~~Accounting~~New ~~Standards~~Talos, ~~Codification~~entered into a Transaction Agreement (the “~~ASC~~Transaction Agreement”) ~~852~~with Talos on November 21, ~~“Reorganizations”~~2017, which ~~resulted~~contemplates ina series of transactions (the ~~Company~~“Transactions”) ~~becoming~~occurring aon ~~new~~the ~~entity~~date ~~for~~of ~~financial~~closing ~~reporting~~of ~~purposes~~the onTransaction Agreement (the ~~Effective~~“Closing”) ~~Date~~that will result in such business combination. AsStone aand ~~result~~Talos will become wholly owned subsidiaries of New Talos. At the ~~adoption~~time of ~~fresh~~the ~~start accounting~~Closing, the ~~Company’s~~parties ~~unaudited~~intend ~~condensed~~that ~~consolidated~~New ~~financial~~Talos ~~statements~~will ~~subsequent~~become a publicly traded entity named Talos Energy Inc. The Transactions include (i) the contribution of 100% of the equity interests in Talos Production to ~~February~~New 28Talos in exchange for shares of New Talos common stock, ~~2017~~(ii) ~~will~~the ~~not~~contribution beby ~~comparable~~entities tocontrolled ~~its~~by ~~financial~~or ~~statements~~affiliated ~~prior~~with toApollo ~~that~~Management ~~date~~(the “Apollo Funds”) and Riverstone (the “Riverstone Funds”) of $102 million in aggregate principal amount of 9.75% ~~See~~Senior ~~Note~~Notes 3due –2022 ~~Fresh~~issued ~~Start~~by ~~Accounting~~Talos Production and Talos Production Finance Inc. (together, the “the Talos Issuers”) to New Talos in exchange for ~~further~~shares ~~details~~of onNew Talos common stock, (iii) the ~~impact~~exchange of ~~fresh~~the ~~start~~second ~~accounting~~lien onbridge loans due 2022 issued by the ~~Company’s~~Talos ~~unaudited~~Issuers ~~condensed~~for ~~consolidated~~newly ~~financial~~issued ~~statements~~11.0% second lien notes issued by the Talos Issuers, and (iv) the exchange of the 7.50% Senior Second Lien Notes due 2022 (the “2022 Second Lien Notes”) issued by Stone for newly issued 11.0% second lien notes issued by the Talos Issuers.

~~References~~Under tothe ~~“Successor”~~terms orof ~~“Successor~~the ~~Company”~~Transaction ~~relate~~Agreement, toeach outstanding share of Stone common stock will be exchanged for one share of New Talos common stock and the ~~financial~~current ~~position~~Talos stakeholders (including the Apollo Funds and ~~results~~the Riverstone Funds) will be issued an aggregate of ~~operations~~approximately 34.1 million shares of New Talos common stock. After the ~~reorganized~~completion ~~Company~~of ~~subsequent~~the toTransactions ~~February~~contemplated 28by the Transaction Agreement, ~~2017.~~holders ~~References~~of Stone common stock immediately prior to ~~“Predecessor”~~the orcombination ~~“Predecessor~~will ~~Company”~~collectively ~~relate~~hold to37% of the ~~financial~~outstanding ~~position~~New Talos common stock and ~~results~~Talos ofEnergy ~~operations~~stakeholders will hold 63% of the ~~Company~~outstanding ~~prior~~New Talos common stock. Outstanding warrants to, acquire Stone common stock will become warrants to acquire New Talos common stock with terms and ~~including,~~conditions ~~February~~substantially ~~28,~~identical ~~2017~~to their existing terms and conditions. The combination was unanimously approved by the boards of directors of Stone and Talos Energy.

On March 20, 2018, the Talos Issuers launched an offer to exchange (the “Exchange Offer”) Stone’s outstanding 2022 Second Lien Notes for newly issued 11.0% second lien notes due 2022 of the Talos Issuers. Concurrently with the Exchange Offer, the Talos Issuers solicited and received sufficient consents from the holders of the 2022 Second Lien Notes to adopt certain proposed amendments to the indenture governing the 2022 Second Lien Notes (the “Stone Notes Indenture”) and to release the collateral securing the obligations under the 2022 Second Lien Notes. Stone entered into supplemental indentures related to the amendments and the release of collateral. The supplemental indentures, which will not become operative until the tendered 2022 Second Lien Notes are accepted for exchange by the Talos Issuers, will amend the Stone Notes Indenture to, among other things, eliminate or modify substantially all of the restrictive

Table of Contents

covenants, certain reporting obligations, certain events of default and related provisions contained in the Stone Notes Indenture and to release the collateral securing the 2022 Second Lien Notes.

Pursuant to a consent solicitation statement/prospectus dated April 9, 2018, which was included as part of a Registration Statement on Form S-4 filed by New Talos, Stone solicited written consents from its stockholders to adopt the Transaction Agreement, and thereby approve and adopt the Transactions. As of May 3, 2018, stockholders party to voting agreements with Stone and Talos Energy that owned 10,212,937 shares of Stone common stock as of April 5, 2018 had delivered written consents adopting the Transaction Agreement, and thereby approving and adopting the Transactions. The Stone stockholders that delivered written consents collectively own approximately 51.1% of the outstanding shares of Stone common stock. As a result, no further action by any Stone stockholder is required under applicable law or otherwise to adopt the Transaction Agreement, and thereby approve and adopt the Transactions.

Reorganization and Emergence from Voluntary Reorganization Under Chapter 11 Proceedings

On December 14, 2016, the Company and certain of its subsidiaries (the “Debtors”) filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) to pursue a prepackaged plan of reorganization (the “Plan”) under the provisions of Chapter 11 of the United States Bankruptcy Code. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan, and on February 28, 2017, the Plan became effective (the “Effective Date”) and the Debtors emerged from bankruptcy. See Note 2 – Reorganization for additional details.

Upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification (“ASC”) 852, “Reorganizations”, which resulted in 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 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.

Use of Estimates

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and 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 Company’s operating environment changes. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization (“DD&A”) expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, income taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, estimated fair value of derivative contracts, contingencies and fair value estimates, including estimates of reorganization value, enterprise value and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting.

8Recently Adopted Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606)” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The new standard supersedes current revenue recognition requirements and industry-specific guidance. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. We adopted this new standard on January 1, 2018 using the modified retrospective approach by recognizing the cumulative effect of initially applying the new standard as an adjustment to the opening balance of accumulated deficit. We implemented the necessary changes to our business processes, systems and controls to support recognition and disclosure of this ASU upon adoption. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows, but did result in increased disclosures related to revenue recognition policies and disaggregation of revenues. See Note 13 – Revenue Recognition for additional information.

Table of Contents

In November 2016, the FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230) – Restricted Cash”, which requires that amounts generally described as restricted cash be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. We adopted this new standard on January 1, 2018. Retrospective presentation was required. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows. In accordance with ASU 2016-18, we have included restricted cash as part of the beginning-of-period and end-of-period cash balances on the condensed consolidated statement of cash flows. At February 28, 2017 (Predecessor) and March 31, 2017 (Successor), we had restricted cash of $75.5 million and $74.1 million, respectively. We had no restricted cash at March 31, 2018 (Successor). For the period from January 1, 2017 through February 28, 2017 (Predecessor) and the period from March 1, 2017 through March 31, 2017 (Successor), removing the change in restricted funds from the condensed consolidated statement of cash flows resulted in an increase of $75.5 million and a decrease of $1.5 million, respectively, in our net cash provided by investing activities.

Recently Issued Accounting Standards

In ~~May~~February ~~2014~~2016, the ~~Financial Accounting Standards Board (“~~FASB”) issued ~~Accounting Standards Update (“~~ASU”) ~~2014~~2016-0902, “~~Revenue~~Leases ~~from Contracts with Customers~~ (Topic ~~606~~842)” to ~~clarify~~increase ~~the~~transparency ~~principles~~and ~~for~~comparability ~~recognizing~~among ~~revenue~~organizations ~~and~~by torecognizing ~~develop~~lease aassets ~~common~~and ~~revenue~~lease ~~standard~~liabilities ~~and~~on ~~disclosure~~the ~~requirements.~~balance ~~The~~sheet ~~standard~~and ~~may~~disclosing bekey ~~applied~~information ~~retrospectively~~about orleasing ~~using~~arrangements. aThe ~~modified~~standard ~~retrospective~~is ~~approach,~~effective ~~with~~for ~~the~~public ~~cumulative~~companies ~~effect~~for offiscal ~~initially~~years ~~applying~~beginning ~~ASU~~after ~~2014-09~~December ~~recognized~~15, at2018, ~~the~~and ~~date~~for ofinterim ~~initial~~periods ~~application.~~within Inthose ~~August~~fiscal ~~2015~~years, ~~the~~with ~~FASB~~earlier ~~issued~~application ~~ASU~~permitted. ~~2015-14,~~Upon ~~deferring~~adoption the ~~effective~~lessee ~~date~~will ofapply ~~ASU 2014-09 by one year. As a result,~~ the new standard isretrospectively ~~effective~~to ~~for~~all ~~interim and annual~~ periods ~~beginning~~presented on or ~~after~~retrospectively ~~December~~using ~~15,~~a ~~2017.~~cumulative Weeffect ~~expect~~adjustment toin ~~apply~~ the ~~modified~~year ~~retrospective approach upon adoption~~ of ~~this standard~~adoption. ~~Although~~We we are ~~still~~currently 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 and related disclosures.

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. ASU 2016-09 became effective for us 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 extent awards are forfeited. The implementation of this new standard did not have a material effect on our financial statements or related disclosures.

In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815)” to improve the financial reporting of hedging relationships to better reflect an entity’s hedging strategies. The standard expands an entity’s ability to apply hedge accounting for both non-financial and financial risk components and amends the presentation and disclosure requirements. Additionally, ASU 2017-12 eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be recorded in the same income statement line as the earnings effect of the hedged item. The standard is effective for public companies for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted. The standard must be adopted by applying a modified retrospective approach to existing designated hedging relationships as of the adoption date, with a cumulative effect adjustment recorded to opening retained earnings as of the initial adoption date. We are currently evaluating the effect that this new standard may have on our financial statements and related disclosures.

NOTE 2 – REORGANIZATION

OnIn ~~December~~connection ~~14,~~with ~~2016~~our reorganization, ~~the~~we ~~Debtors~~sold ~~filed~~certain ~~Bankruptcy~~producing ~~Petitions~~properties ~~seeking~~and ~~relief~~acreage, ~~under~~including approximately 86,000 net acres, in the ~~provisions~~Appalachia regions of ~~Chapter~~Pennsylvania 11and ofWest Virginia (the ~~Bankruptcy~~“Appalachia ~~Code~~Properties”) to ~~pursue~~EQT aCorporation, ~~prepackaged~~through ~~plan~~its ofwholly-owned ~~reorganization.~~subsidiary OnEQT Production Company (“EQT”), on February 1527, 2017, for net cash consideration of approximately $522.5 million. A portion of the ~~Bankruptcy~~consideration ~~Court~~received ~~entered~~from anthe ~~order~~sale ~~confirming~~of the Appalachia Properties was used to fund the Company’s cash payment obligations under the Plan, ~~and~~as ondescribed ~~February~~below. 28Additionally, ~~2017~~the Company used a portion of the cash consideration received to pay TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”), a break-up fee and expense reimbursements totaling approximately $11.5 million related to the ~~Plan~~termination ~~became~~of ~~effective~~a purchase and sale agreement for the ~~Debtors~~Appalachia ~~emerged~~Properties ~~from~~prior ~~bankruptcy~~to the sale to EQT. See Note 5 – Divestiture for additional information on the sale of the Appalachia Properties.

Prior to the filing of the Bankruptcy Petitions, the Debtors and certain holders of the 1 3⁄4% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) and the 7 1⁄2% Senior Notes due 2022 (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.

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 accordance with the Bidding Procedures, Stone conducted an auction for the sale of 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”), with a final purchase price of $527 million in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court, with an upward adjustment to

Table of Contents

the purchase price of up to $16 million in 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 cash, 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 consideration received to pay Tug Hill a break-up fee and expense reimbursements totaling approximately $11.5 million, which is recognized as other expense in the statement of operations for the period of January 1, 2017 through February 28, 2017 (Predecessor). See Note 7 – Divestiture for additional information on the sale of the 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 7 ½% Senior Notes due 2022 (the “2022 Notes”) and 1 ¾% Senior Convertible Notes due 2017 (the “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 ~~7.5% Senior Second Lien Notes due~~ 2022 ~~(the “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~~Fourth ~~Credit~~Amended ~~Agreement~~and ~~was~~Restated ~~amended~~Credit ~~and~~Agreement, ~~restated~~dated as ~~the~~of ~~Amended~~June ~~Credit~~24, ~~Agreement~~2014, (as ~~defined~~amended, inmodified, ~~Note~~or 10otherwise –supplemented ~~Debt).~~from ~~The~~time ~~obligations owed~~ to ~~the~~time ~~lenders under~~ (the “Pre-Emergence Credit Agreement”) ~~were~~was ~~converted~~amended toand ~~obligations~~restated ~~under~~as the Amended ~~Credit Agreement.~~

Table of Contents

Credit Agreement (as defined in Note 8 – 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 ordinary course of business to the extent the claims were undisputed.

For further information regarding the equity and debt instruments of the Predecessor Company and the 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 2 – 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.

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.

Table of Contents

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 $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%.

Table of Contents

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,~~169~~278
Less: Fair value of debt	(236,261		)
Less: Fair value of warrants	(15,648		)
Fair value of Successor common stock	$	~~538~~539,~~980~~089
Shares issued upon emergence	20,000
Per share value	$	26.95

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,~~169~~278
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,~~011~~120

Table of Contents

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):

129

Table of Contents

	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	1011,~~924~~033			875			(3)	(124		)	(12)	11,~~675~~784
Total current assets	276,~~086~~195			50,118				(124		)		326,~~080~~189
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,~~375~~484		$	(271,082	)		$	290,718			$	1,139,~~011~~120
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,~~428~~537			(10)	—				554,~~428~~537
Accumulated deficit	(2,309,~~788~~679		)	2,073,~~984~~875			(11)	235,804			(15)	—
Total stockholders’ equity	(649,~~782~~673		)	968,606				235,804				554,~~628~~737
Total liabilities and stockholders’ equity	$	1,119,~~375~~484		$	(271,082	)		$	290,718			$	1,139,~~011~~120

1310

Table of Contents

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 (in thousands):



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 75 – Divestiture for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of $522~~,472~~.5 million included cash consideration of $512~~,472~~.5 million received at closing and a $10~~,000~~.0 million indemnity escrow which was released subsequent to emergence from bankruptcy (see Reorganization Adjustments item number 2 below).

(b) Reflects the movement of $75~~,000~~.0 million 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 108 – Debt), and $~~547~~0.5 million 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~~.2 million of emergence and success fees, $2~~,600~~.7 million of professional fees and $2~~,395~~.4 million of payments made to seismic providers in settlement of their bankruptcy claims.

2. Reflects a receivable for a $10~~,000~~.0 million indemnity escrow with release delayed until emergence from bankruptcy, net of a $~~699~~0.7 million reimbursement to Tug Hill in connection with the sale of the Appalachia Properties (see Note 72 – ~~Divestiture~~Reorganization).


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~~.6 million of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a $1~~,750~~.8 million prepayment made to Tug Hill in October 2016.

6. Reflects the accrual of $2~~,008~~.0 million in expected bonus payments under the ~~KEIP~~Key ~~(as~~Executive ~~defined~~Incentive inPlan ~~Note 5 – Share–Based Compensation~~ and ~~Employee Benefit Plans) and~~ a $~~395~~0.4 million termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of $2~~,598~~.6 million in connection with the sale of the Appalachia Properties.

7. Reflects the repayment of $341~~,500~~.5 million of outstanding borrowings under the Pre-Emergence Credit Agreement and the issuance of $225~~,000~~ million 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 (in thousands):

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	(~~538~~539,~~980~~089		)
Fair value of warrants issued to unsecured creditors	(15,648		)
Gain on settlement of liabilities subject to compromise	$	230,~~554~~445

1411

Table of Contents


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 (in thousands):

Gain on settlement of liabilities subject to compromise	$	230,~~554~~445
Professional and other fees paid at emergence	(10,648		)
Write-off of unamortized deferred financing costs	(2,577		)
Write-off of unamortized debt issuance costs	(2,577		)
Other reorganization adjustments	(1,915		)
Net impact to reorganization items	215,~~414~~305
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,~~984~~875

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 fromJanuary 1, 2017throughFebruary 28, 2017
Gain on settlement of liabilities subject to compromise	$	230,~~554~~445
Fresh start valuation adjustments	235,804
Reorganization professional fees and other expenses	(20,~~512~~403		)
Write-off of deferred financing costs	(2,577		)
Write-off of unamortized debt issuance 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 $98.19 million of other reorganization professional fees and expenses paid on the Effective Date.

1512

Table of Contents

NOTE 4 – ~~STOCKHOLDERS’~~EARNINGS ~~EQUITY~~PER SHARE

~~Common~~On ~~Stock~~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 for further details.

AsThe ~~discussed~~following intable ~~Note~~sets 2forth –the ~~Reorganization,~~calculation ~~upon emergence from bankruptcy, all existing shares~~ of ~~Predecessor~~basic ~~common stock were cancelled,~~ and ~~the~~diluted ~~Successor~~weighted ~~Company~~average ~~issued an aggregate of 20.0 million~~ shares ofoutstanding ~~New~~and ~~Common~~earnings ~~Stock, par value $0.01~~ per share, tofor the ~~Predecessor~~indicated ~~Company’s~~periods ~~existing~~(in ~~common~~thousands, ~~stockholders~~except ~~and~~per ~~holders~~share ~~of the 2017 Convertible Notes and the 2022 Notes pursuant to the Plan.~~ amounts):

Warrants



	Successor						Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017
Income (numerator):
Basic:
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Net income attributable to participating securities	(57		)	—			(4,995		)
Net income (loss) attributable to common stock - basic	$	18,251		$	(259,613	)	$	625,322
Diluted:
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Net income attributable to participating securities	(56		)	—			(4,995		)
Net income (loss) attributable to common stock - diluted	$	18,252		$	(259,613	)	$	625,322
Weighted average shares (denominator):
Weighted average shares - basic	19,998			19,997			5,634
Dilutive effect of stock options	—			—			—
Dilutive effect of warrants	—			—			—
Dilutive effect of convertible notes	—			—			—
Weighted average shares - diluted	19,998			19,997			5,634
Basic income (loss) per share	$	0.91		$	(12.98	)	$	110.99
Diluted income (loss) per share	$	0.91		$	(12.98	)	$	110.99

AsAll ~~discussed~~outstanding instock ~~Note~~options 2were –considered ~~Reorganization,~~antidilutive during the ~~Predecessor~~period ~~Company’s~~from ~~existing~~January ~~common~~1, ~~stockholders~~2017 ~~received~~through ~~warrants~~February to28, ~~purchase~~2017 ~~approximately~~(Predecessor) ~~3.5~~(10,400 ~~million~~ shares) ofbecause ~~New~~the ~~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~~options ofexceeded ~~certain business combinations or sale transactions involving~~ the ~~Company.~~average ~~The~~price ~~Company allocated $15.6 million~~ of ~~the~~our ~~enterprise~~common ~~value~~stock tofor the ~~warrants~~applicable ~~which~~period. On isFebruary ~~reflected~~28, in2017, ~~“Successor~~upon ~~additional~~emergence ~~paid-in~~from ~~capital”~~bankruptcy, onall ~~the~~outstanding ~~unaudited~~stock ~~condensed~~options ~~consolidated~~were ~~balance sheet at September 30, 2017 (Successor)~~cancelled.

~~NOTE~~On 5February –28, ~~SHARE~~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 –~~BASED~~ ~~COMPENSATION~~Reorganization. ~~AND~~For ~~EMPLOYEE~~the ~~BENEFIT~~three ~~PLANS~~months ended March 31, 2018 (Successor), all outstanding warrants (approximately 3.5 million) were considered antidilutive because the exercise price of the warrants exceeded the average price of our common stock for the applicable period. For the period of March 1, 2017 through March 31, 2017 (Successor), all outstanding warrants (approximately 3.5 million) were antidilutive because we had a net loss for such period.

The Predecessor ~~Awards~~Company had no outstanding restricted stock units. The board of directors of the Successor Company (the “Board”) received grants of restricted stock units on March 1, 2017. For the period from March 1, 2017 through March 31, 2017 (Successor), all outstanding restricted stock units (62,137) were considered antidilutive because we had a net loss for such period.

~~Immediately~~For ~~prior to emergence,~~ the ~~vesting~~period offrom ~~all~~January ~~Predecessor outstanding~~1, ~~unvested~~2017 ~~share-based~~through ~~awards~~February ~~for~~28, ~~non-executive~~2017 ~~employees was accelerated and~~(Predecessor), asthe aaverage ~~result,~~price ~~all~~of ~~unrecognized~~our ~~compensation~~common ~~cost~~stock ~~related~~was toless ~~such~~than ~~awards~~the ~~was~~effective ~~recognized,~~conversion ~~with~~price ~~$1.7~~for ~~million~~the ~~expensed~~2017 asConvertible ~~salaries~~Notes, ~~general~~resulting ~~and~~in ~~administrative~~no ~~(“SG&A”)~~dilutive ~~expense~~effect inon the ~~Predecessor~~diluted ~~Company~~earnings ~~statement~~per ofshare ~~operations~~computation ~~during~~for ~~the~~such period. On ~~from~~February ~~January 1~~28, 2017, ~~through~~upon ~~February~~emergence 28from bankruptcy, the 2017, ~~and~~Convertible ~~$0.6~~Notes ~~million~~were ~~capitalized~~cancelled. ~~into~~See ~~oil~~Note ~~and~~2 ~~gas~~– ~~properties~~Reorganization.

~~Upon~~During ~~emergence~~the ~~from~~three ~~bankruptcy,~~months ~~all~~ended ~~Predecessor outstanding~~March 31, ~~unvested~~2018 ~~restricted~~(Successor), 682 shares ~~held~~of bycommon stock of the Successor Company’s ~~executives~~ were ~~cancelled~~issued ~~and~~from ~~exchanged~~authorized ~~for~~shares aupon ~~proportionate~~the ~~share~~lapsing of ~~the~~forfeiture 5%restrictions of ~~New~~restricted ~~Common~~stock ~~Stock,~~for ~~plus~~employees. aDuring ~~proportionate share of~~ the ~~warrants~~period ~~for~~from ~~ownership~~March of1, up2017 tothrough ~~15%~~March 31, of2017 ~~the~~ (Successor), ~~Company’s~~we ~~common~~had ~~equity.~~no ~~Vesting~~issuances ~~continues~~of inshares ~~accordance~~of ~~with~~our ~~the~~common ~~applicable~~stock. ~~vesting~~During ~~provisions of~~ the ~~original~~period ~~awards.~~from AsJanuary ~~of September 30~~1, 2017, ~~there~~through ~~was~~February ~~$14~~28, ~~thousand~~2017 of(Predecessor), ~~unrecognized~~47,390 ~~compensation cost related to unvested restricted~~ shares ~~held~~of byPredecessor ~~the~~ Company’s ~~executives.~~common ~~The~~stock ~~current~~were ~~weighted~~issued ~~average~~from ~~remaining~~authorized ~~vesting~~shares ~~period~~upon the granting of ~~such~~stock awards isand ~~approximately~~the ~~three~~lapsing ~~months.~~of ~~All~~forfeiture ~~other~~restrictions ~~Predecessor~~of ~~Company~~restricted ~~executive~~stock ~~share-based~~for ~~awards~~employees ~~were~~and ~~cancelled~~nonemployee ~~upon emergence from bankruptcy~~directors.

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 $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.13

Successor Awards

On March 1, 2017, the board of directors of the Successor Company (the “Board”) received grants of restricted stock units under the 2017 LTIP (see 2017 Long-Term Incentive Plan below). The restricted stock units 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 $1.7 million, based on a per share grant date fair value of $26.95. As of September 30, 2017, there was $0.9 million of unrecognized compensation cost related to such restricted stock units, with a current weighted average remaining vesting period of approximately seven months.

2017 Long-Term Incentive Plan

On the Effective Date, pursuant to the Plan, the Stone Energy Corporation 2017 Long-Term Incentive Plan (the “2017 LTIP”) 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 LTIP 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

Table of Contents

~~the~~NOTE ~~2017~~5 ~~LTIP~~– is 2,614,379. As of November 1, 2017, other than the grant of the 62,137 restricted stock units to the Board (see Successor Awards above), there have been no other issuances or awards of stock under the 2017 LTIP.DIVESTITURE

~~Key~~On ~~Executive~~February ~~Incentive~~27, ~~Plan~~2017, we completed the sale of the Appalachia Properties to EQT for net cash consideration of approximately $522.5 million. We no longer have assets or operations in Appalachia. Since accounting for the sale of these oil and gas properties as a reduction of 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 $213.5 million during the period from January 1, 2017 through February 28, 2017 (Predecessor), computed as follows (in thousands):

Pursuant to the terms of the Executive Claims Settlement Agreement approved by the Bankruptcy Court on January 10, 2017, the Company’s 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 Company’s executives were allowed to participate. Future payments to the Company’s executives under the KEIP were limited to $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 the Company’s executives under the KEIP was made subsequent to consummation of the bankruptcy cases, on April 24, 2017, and the second payment was made on May 30, 2017.



Net consideration received for sale of Appalachia Properties		$	522,472
Add:	Release of funds held in suspense	4,139
	Transfer of asset retirement obligations	8,672
	Other adjustments, net	2,597
Less:	Transaction costs	(7,087		)
	Carrying value of properties sold	(317,340		)
Gain on sale		$	213,453

2017 Annual Incentive Compensation Plan

On July 25, 2017, the Board approved the Stone Energy Corporation 2017 Annual Incentive Compensation Plan (the “2017 Annual Incentive Plan”) for all salaried employees (other than the interim chief executive officer) of the Company. The 2017 Annual Incentive Plan is a performance-based incentive program that provides award opportunities based on the Company’s annual performance in certain performance measures as defined by the Board. The 2017 Annual Incentive Plan replaced the Company’s 2005 Annual Incentive Compensation Plan. We recognized a charge of $4.1 million during the three months ended September 30, 2017 (Successor), net of amounts capitalized, representing a pro-rated portion of the 2017 estimated annual incentive compensation awards, for the nine months ended September 30, 2017. This charge is reflected in incentive compensation expense on the statement of operations.

Retention Award Agreement

On July 25, 2017, the Board approved retention awards and the form of Stone Energy Corporation Retention Award Agreement (the “Retention Award Agreement”) and authorized the Company to enter into Retention Award Agreements with certain executive officers and employees of the Company. The Retention Award Agreement provides for a retention award to certain individuals to be paid in a lump sum cash payment within 30 days of the earliest to occur of (i) the first anniversary (June 1, 2018) of the effective date of the Retention Award Agreement, subject to the individual remaining employed by the Company or a subsidiary of the Company on such date, (ii) a change in control of the Company or (iii) a termination of the individual’s employment with the Company (a) due to death, (b) by the Company without “cause” or (c) by the individual for “good reason.” We recognized a charge of $0.5 million during the three months ended September 30, 2017 (Successor), representing a pro-rated portion of estimated retention awards for the period from June 1, 2017 through September 30, 2017. This charge is reflected in incentive compensation expense on the statement of operations.

Executive Severance Plan

On July 25, 2017, the Board approved the Stone Energy Corporation Executive Severance Plan (the “Executive Severance Plan”), which provides for the payment of severance and change in control benefits to the executive officers (other than the interim chief executive officer) of the Company. Pursuant to the Executive Severance Plan, if a covered executive officer is terminated (i) by the Company without “cause” or (ii) by the executive officer for “good reason” (each, an “Involuntary Termination”), the executive officer will receive (i) a lump sum cash payment in an amount equal to 1.0x or 1.5x the executive officer’s annual base salary, (ii) a lump sum cash payment equal to 100% of the executive officer’s annual bonus opportunity, at target, prorated by the number of days that have elapsed from January 1 of that calendar year, (iii) six months of health benefit continuation for the executive officer and the executive officer’s dependents, (iv) accelerated vesting of any outstanding and unvested equity awards, (v) certain outplacement services and (vi) any unpaid portion of the executive officer’s annual pay as of the date of the Involuntary Termination. The Executive Severance Plan replaced the Stone Energy Corporation Executive Severance Plan dated December 13, 2016.

Table of Contents

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 tables set 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
	Three Months EndedSeptember 30, 2017			Three Months EndedSeptember 30, 2016
Income (numerator):
Basic:
Net income (loss)	$	1,297		$	(89,635	)
Net income attributable to participating securities	(4		)	—
Net income (loss) attributable to common stock - basic	$	1,293		$	(89,635	)
Diluted:
Net income (loss)	$	1,297		$	(89,635	)
Net income attributable to participating securities	(4		)	—
Net income (loss) attributable to common stock - diluted	$	1,293		$	(89,635	)
Weighted average shares (denominator):
Weighted average shares - basic	19,997			5,600
Dilutive effect of stock options	—			—
Dilutive effect of warrants	—			—
Dilutive effect of convertible notes	—			—
Weighted average shares - diluted	19,997			5,600
Basic income (loss) per share	$	0.06		$	(16.01	)
Diluted income (loss) per share	$	0.06		$	(16.01	)

	Successor			Predecessor
	Period fromMarch 1, 2017throughSeptember 30, 2017			Period fromJanuary 1, 2017throughFebruary 28, 2017			Nine Months EndedSeptember 30, 2016
Income (numerator):
Basic:
Net income (loss)	$	(264,777	)	$	630,317		$	(474,180	)
Net income attributable to participating securities	—			(4,995		)	—
Net income (loss) attributable to common stock - basic	$	(264,777	)	$	625,322		$	(474,180	)
Diluted:
Net income (loss)	$	(264,777	)	$	630,317		$	(474,180	)
Net income attributable to participating securities	—			(4,995		)	—
Net income (loss) attributable to common stock - diluted	$	(264,777	)	$	625,322		$	(474,180	)
Weighted average shares (denominator):
Weighted average shares - basic	19,997			5,634			5,585
Dilutive effect of stock options	—			—			—
Dilutive effect of warrants	—			—			—
Dilutive effect of convertible notes	—			—			—
Weighted average shares - diluted	19,997			5,634			5,585
Basic income (loss) per share	$	(13.24	)	$	110.99		$	(84.90	)
Diluted income (loss) per share	$	(13.24	)	$	110.99		$	(84.90	)

Table of Contents

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 and nine months ended September 30, 2016 (Predecessor), all outstanding stock options were considered antidilutive (approximately 12,900 shares) because we had net losses for such periods. 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 three months ended September 30, 2017 (Successor), all outstanding warrants (approximately 3,529,000) were considered antidilutive because the exercise price of the warrants exceeded the average price of our common stock for the applicable period. For the period of March 1, 2017 through September 30, 2017 (Successor), all outstanding warrants (approximately 3,529,000) were antidilutive because we had a net loss for such period.

The Predecessor Company had no outstanding restricted stock units. The Board received grants of restricted stock units on March 1, 2017. See Note 5 – Share-Based Compensation and Employee Benefit Plans. For the period from March 1, 2017 through September 30, 2017 (Successor), 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 and nine months ended September 30, 2016 (Predecessor), the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such periods. On February 28, 2017, upon emergence from bankruptcy, the 2017 Convertible Notes were cancelled. See Note 2 – Reorganization.

During the three months ended September 30, 2017 (Successor), there were no issuances of common stock of the Successor Company. During the period from March 1, 2017 through September 30, 2017 (Successor), 1,195 shares of common stock of the Successor Company were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock for employees. During the periods from January 1, 2017 through February 28, 2017 (Predecessor) and the three and nine months ended September 30, 2016 (Predecessor), approximately 47,390 shares, 12,900 shares and 75,100 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 cash 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. We no longer have assets or operations in Appalachia. Since accounting for the sale of these oil and gas properties as a reduction of 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 $213.5 million during the period from January 1, 2017 through February 28, 2017 (Predecessor), 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.

19NOTE 6 – INVESTMENT IN OIL AND GAS PROPERTIES

Table of Contents

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, probable and possible reserves and unevaluated properties (including inventory) 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~~2018 (Successor), ~~our~~the ~~ceiling~~present ~~test~~value ~~computation resulted in a write-down~~ of ~~our~~the ~~U.S.~~estimated ~~oil~~future ~~and~~net ~~gas~~cash ~~properties~~flows offrom ~~$256.4~~proved ~~million~~reserves was based on twelve-month average prices, net of applicable differentials, of $4553.4004 per Bbl of oil, $2.2428 per Mcf of natural gas and $1925.1827 per Bbl of natural gas liquids (“NGLs”). ~~The~~Using ~~write-down~~these ~~at March 31~~prices, ~~2017 is reflected in~~ the ~~statement of operations of the Successor~~ Company’s ~~for~~net ~~the~~capitalized ~~period~~costs from March 1, 2017 through September 30, 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~~proved oil and ~~gas~~natural ~~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~~at ~~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~~2018 ~~were designated as cash flow hedges~~ (~~see Note 9 – Derivative Instruments and Hedging Activities~~Successor), ~~the~~did ~~write-down at March 31, 2017 was~~ not ~~affected~~exceed bythe ~~hedging~~ceiling amount.

At ~~September~~March 3031, ~~2016~~2017 (~~Predecessor~~Successor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $36256.54 million based on twelve-month average prices, net of applicable differentials, of $4045.5140 per Bbl of oil, $12.9924 per Mcf of natural gas and $1319.8818 per Bbl of NGLs. The write-down at ~~September 30~~March 31, ~~2016~~2017 ~~was~~is ~~decreased~~reflected byin ~~$9.6~~the ~~million~~statement asof aoperations ~~result~~ of ~~hedges.~~the AtSuccessor ~~June~~Company ~~30,~~for ~~2016~~the ~~(Predecessor),~~period ~~our~~from ~~ceiling~~March ~~test~~1, ~~computation~~2017 ~~resulted~~through inMarch a31, ~~write-down~~2017 ~~of our U.S. oil~~ and ~~gas~~was ~~properties~~primarily ofdue ~~$118.6~~to ~~million~~differences ~~based~~between onthe trailing twelve-month average ~~prices,~~pricing ~~net~~assumption ofused ~~applicable~~in ~~differentials,~~calculating ofthe ~~$43.49~~ceiling ~~per~~test ~~Bbl~~and ofthe ~~oil,~~forward ~~$1.93~~prices ~~per~~used ~~Mcf~~in offresh ~~natural~~start ~~gas~~accounting ~~and~~to ~~$9.33~~estimate ~~per~~the ~~Bbl~~fair value of ~~NGLs.~~our ~~The~~oil ~~write-down~~and atgas ~~June~~properties ~~30,~~on ~~2016~~the ~~was~~fresh ~~decreased~~start byreporting ~~$18.1~~date ~~million~~of asFebruary a28, ~~result of hedges~~2017. AtWeighted ~~March 31,~~average ~~2016~~commodity ~~(Predecessor),~~prices ~~our~~used ~~ceiling~~in ~~test~~the ~~computation~~determination ~~resulted~~of inthe afair ~~write-down~~value of our ~~U.S.~~ oil and gas properties offor ~~$128.9~~purposes ~~million based on twelve-month average prices, net~~ of ~~applicable~~fresh ~~differentials,~~start ofaccounting were $4656.7201 per Bbl of oil, $2.0152 per Mcf of natural gas and $1314.6518 per Bbl of NGLs~~. At March 31~~, ~~2016,~~net ~~the write-down~~ of ~~oil~~applicable ~~and gas properties also included $0~~differentials.3 ~~million~~Since ~~related~~none toof our ~~Canadian~~derivatives ~~oil~~as ~~and gas properties, which were deemed to be fully impaired at the end~~ of ~~2015. The write-down at~~ March 31, ~~2016~~2017 ~~was~~were ~~decreased~~designated ~~by $23 million~~ as acash ~~result~~flow of hedges. ~~The~~(see ~~September~~Note ~~30,~~7 ~~June~~– 30Derivative Instruments and ~~March~~Hedging 31Activities), ~~2016~~the write-~~downs~~down ~~are~~at ~~reflected~~March in31, ~~the~~2017 ~~statement~~was ofnot ~~operations~~affected ofby ~~the Predecessor Company~~hedging.

NOTE 97 – 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 typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products were 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, 2018 and 2019 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).14

Table of Contents

WeMonthly ~~have~~settlements ~~entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion~~ of ~~our~~effective ~~expected~~hedges ~~2017,~~are ~~2018~~reflected ~~and~~in ~~2019~~revenue from oil and natural gas production ~~from the Gulf Coast Basin~~. ~~All~~Monthly settlements of ~~our~~ineffective ~~derivative~~hedges ~~transactions have been carried out in the over-the-counter market~~ and ~~are~~derivatives not ~~typically~~designated ~~subject~~or ~~to margin-deposit requirements. The use of derivative instruments involves the risk~~ that ~~the~~do ~~counterparties~~not ~~will~~qualify befor ~~unable~~hedge toaccounting ~~meet~~are ~~the~~recognized ~~financial~~in ~~terms~~earnings ofthrough ~~such~~derivative ~~transactions~~income (expense). The ~~counterparties~~resulting tocash flows from all ofmonthly ~~our~~settlements ~~derivative~~are ~~instruments~~reported ~~have~~as ancash ~~“investment~~flows ~~grade”~~from ~~credit~~operating ~~rating~~activities. WeWith ~~monitor~~respect ~~the~~to ~~credit ratings of~~ our ~~derivative~~2017, ~~counterparties~~2018 onand an2019 ~~ongoing~~commodity ~~basis. Although we typically enter into~~ derivative contracts ~~with multiple counterparties to mitigate our exposure to any individual counterparty~~, ifwe ~~any~~elected ~~of our counterparties were~~ to ~~default~~not ondesignate ~~its~~these ~~obligations~~contracts toas uscash ~~under~~flow ~~the~~hedges ~~derivative~~for ~~contracts~~accounting orpurposes. ~~seek bankruptcy protection~~Accordingly, wethe ~~may~~net ~~not~~changes ~~realize~~in the ~~benefit~~mark-to-market ofvaluations ~~some of our derivative instruments~~ and ~~incur~~the amonthly ~~loss.~~settlements Atof ~~November 1,~~these ~~2017, our~~ derivative ~~instruments~~contracts ~~were~~have ~~with five counterparties~~been, ~~two~~or ofwill ~~which accounted for approximately 64% of our contracted volumes. Currently~~be, ~~all~~recorded ofin ~~our~~earnings ~~outstanding~~through derivative ~~instruments~~income ~~are with lenders under our current bank credit facility~~(expense).

~~Put~~We ~~contracts~~have ~~are~~entered ~~purchased~~into atput acontracts, ~~rate~~fixed-price ~~per~~swaps ~~unit~~and ofcollar ~~hedged~~contracts ~~production that fluctuates~~ with ~~the~~various ~~commodity~~counterparties ~~futures~~for ~~market.~~a ~~The~~portion ~~historical cost~~ of ~~the~~our ~~put~~expected ~~contract~~2018 ~~represents~~and ~~our~~2019 ~~maximum~~oil ~~cash~~and ~~exposure.~~natural Wegas ~~are~~production ~~not~~from ~~obligated~~the toGulf ~~make~~Coast ~~any~~Basin. ~~further~~All ~~payments~~of ~~under~~our ~~the~~derivative ~~put~~transactions ~~contract~~have ~~regardless~~been ofcarried ~~future~~out ~~commodity~~in ~~price~~the ~~fluctuations.~~over-the-counter ~~Under~~market ~~put~~and ~~contracts,~~are ~~monthly~~not ~~payments~~typically ~~are~~subject ~~made~~ to usmargin-deposit ifrequirements. ~~the~~The ~~New~~use ~~York~~of ~~Mercantile~~derivative ~~Exchange~~instruments ~~(“NYMEX”)~~involves ~~prices~~the ~~fall~~risk ~~below~~that the ~~agreed~~counterparties ~~upon~~will ~~floor~~be ~~price,~~unable ~~while allowing us~~ to ~~fully~~meet ~~participate~~the infinancial ~~commodity~~terms ~~prices~~of ~~above~~such ~~the floor~~transactions. ~~Swaps~~The ~~typically~~counterparties ~~provide~~to ~~for~~all ~~monthly~~of ~~payments~~our byderivative usinstruments ifhave ~~prices~~an ~~rise~~“investment ~~above~~grade” ~~the~~credit ~~swap~~rating. ~~price~~We ormonitor ~~monthly~~the ~~payments~~credit toratings usof ifour ~~prices~~derivative ~~fall~~counterparties ~~below~~on ~~the~~an ~~swap~~ongoing ~~price~~basis. ~~Collar~~Although ~~contracts~~we typically ~~require~~enter ~~payments~~into byderivative uscontracts ifwith ~~the~~multiple ~~NYMEX~~counterparties ~~average~~to ~~closing~~mitigate ~~price~~our isexposure ~~above~~to ~~the~~any ~~ceiling~~individual ~~price~~counterparty, ~~or payments to us~~ if ~~the~~any ~~NYMEX~~of ~~average~~our ~~closing~~counterparties ~~price~~were isto ~~below~~default ~~the~~on ~~floor~~its ~~price.~~obligations ~~Settlements~~to ~~for~~us ~~our~~under ~~oil~~the ~~put~~derivative contracts, ~~oil~~or ~~collar~~seek ~~contracts~~bankruptcy ~~and~~protection, ~~fixed-price~~we ~~oil~~may ~~swaps~~not ~~are~~realize ~~based~~the onbenefit anof ~~average~~some of ~~the~~our ~~NYMEX~~derivative ~~closing~~instruments ~~price~~and ~~for~~incur ~~West~~a ~~Texas~~loss. ~~Intermediate~~At ~~crude~~May 7, ~~oil~~2018, ~~during~~our ~~the~~derivative ~~entire~~instruments ~~calendar~~were ~~month.~~with ~~Settlements~~four ~~for~~counterparties, ~~our~~two ~~natural~~of ~~gas~~which ~~collar~~accounted ~~contracts~~for ~~and~~approximately ~~fixed-price~~64% ~~natural~~of ~~gas~~our ~~swaps~~contracted ~~are~~volumes. ~~based~~Currently, onall ~~the~~of ~~NYMEX~~our ~~price~~outstanding ~~for~~derivative ~~the~~instruments ~~last~~are ~~day~~with oflenders aunder ~~respective~~our ~~contract~~current ~~month~~bank credit facility.

Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The ~~following~~historical ~~tables~~cost ~~illustrate~~of the put contract represents our ~~derivative~~maximum ~~positions~~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 Mercantile Exchange (“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 ~~calendar~~monthly ~~years~~payments ~~2017~~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, ~~2018~~oil collar contracts and ~~2019~~fixed-price asoil swaps are based on an average of ~~November 1,~~the ~~2017:~~NYMEX closing price for West Texas Intermediate crude oil during the entire calendar month. Settlements for our natural gas collar contracts are based on the NYMEX price for the last day of a respective contract month.

		Put Contracts (NYMEX)
		Oil
		Daily Volume(Bbls/d)	Price($ per Bbl)
2017	February - December	2,000	$	50.00
2017	July - December	1,000	41.10
2018	January - December	1,000	54.00
2018	January - December	1,000	45.00

The following tables illustrate our derivative positions for calendar years 2018 and 2019 as of May 7, 2018:

		Fixed-Price Swaps (NYMEX)
		Put Contracts (NYMEX)
		Natural Gas			Oil
		Oil
		Daily Volume(MMBtus/d)	Swap Price($ per MMBtu)		Daily Volume(Bbls/d)	Swap Price($ per Bbl)
		Daily Volume(Bbls/d)	Price($ per Bbl)
2017	March - December				1,000	$	53.90
2018	January - December	1,000	$	54.00
2017	July - December	11,000	$	3.00
2018	January - December	1,000	45.00
2017	October - December				1,000	52.10
2018	January - December				1,000	52.50
2018	January - December				1,000	51.98
2018	January - December				1,000	53.67
2019	January - December				1,000	51.00
2019	January - December				1,000	51.57

		Collar Contracts (NYMEX)
		Fixed-Price Swaps (NYMEX)
		Natural Gas					Oil
		Oil
		Daily Volume(MMBtus/d)	Floor Price($ per MMBtu)		Ceiling Price($ per MMBtu)		Daily Volume(Bbls/d)	Floor Price($ per Bbl)		Ceiling Price($ per Bbl)
		Daily Volume(Bbls/d)	Swap Price($ per Bbl)
2017	March - December						1,000	$	50.00	$	56.45
2018	January - December	1,000	$	52.50
2017	April - December						1,000	50.00		56.75
2018	January - December	1,000	51.98
2018	January - December	61,000	$53.67	~~2.75~~	$	~~3.24~~	~~1,000~~	~~45.00~~		~~55.35~~
2019	January - December	1,000	51.00
2019	January - December	1,000	51.57
2019	January - December	2,000	56.13



		Collar Contracts (NYMEX)
		Natural Gas					Oil
		Daily Volume (MMBtus/d)	Floor Price ($ per MMBtu)		Ceiling Price ($ per MMBtu)		Daily Volume (Bbls/d)	Floor Price ($ per Bbl)		Ceiling Price ($ per Bbl)
2018	January - December	6,000	$	2.75	$	3.24	1,000	$	45.00	$	55.35

Table of Contents

Derivatives not designated or not qualifying as hedging instruments

The following ~~table~~tables ~~discloses~~disclose the location and fair value amounts of derivatives not designated or not qualifying as hedging instruments, as reported in our balance sheet, at ~~September~~March 3031, ~~2017~~2018 (Successor) ~~(in~~and ~~millions). We had no outstanding hedging instruments at~~ December 31, ~~2016~~2017 (~~Predecessor~~Successor) (in thousands).

Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
September 30, 2017
March 31, 2018
(Successor)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	FairValue		Balance Sheet Location	FairValue
Commodity contracts	Current assets: Fair value ofderivative contracts	$	~~2.6~~417	Current liabilities: Fair value of derivative contracts	$	~~0.4~~13,147
	Long-term assets: Fair valueof derivative contracts	~~1.0~~—		Long-term liabilities: Fairvalue of derivative contracts	~~0.1~~4,564
		$	~~3.6~~417		$	~~0.5~~17,711
Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
December 31, 2017
(Successor)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	FairValue		Balance Sheet Location	FairValue
Commodity contracts	Current assets: Fair value ofderivative contracts	$	879	Current liabilities: Fair valueof derivative contracts	$	8,969
	Long-term assets: Fair valueof derivative contracts	—		Long-term liabilities: Fairvalue of derivative contracts	3,085
		$	879		$	12,054

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 designated or not qualifying as hedging instruments on the statement of operations for the three months ended ~~September~~March 3031, ~~2017~~2018 (Successor), the period from January 1, 2017 through February 28, 2017 (Predecessor) and the period from March 1, 2017 through ~~September~~March 3031, 2017 (Successor) (in ~~millions~~thousands).

Gain (Loss) Recognized in Derivative Income (Expense)
	Successor			~~Successor~~			Predecessor
	Three Months EndedSeptember 30, 2017			Period fromMarch 1, 2017throughSeptember 30, 2017			Period fromJanuary 1, 2017throughFebruary 28, 2017
	Three Months EndedMarch 31, 2018			Period fromMarch 1, 2017throughMarch 31, 2017			Period fromJanuary 1, 2017throughFebruary 28, 2017
Description
Commodity contracts:
Cash settlements	$	~~1.2~~(3,429	)	$	~~2.6~~161		$	—
Change in fair value	(~~7.9~~6,119		)	~~(1.~~2,485		)	(1.8,778		)
Total gains (losses) on derivatives not designated or not qualifying as hedging instruments	$	(~~6.7~~9,548	)	$	~~1.4~~2,646		$	(1.8,778	)

~~Derivatives qualifying as hedging instruments~~16

None of our derivative contracts outstanding as of September 30, 2017 (Successor) were designated as accounting hedges. We had no outstanding derivatives at December 31, 2016 (Predecessor). At September 30, 2016, we had outstanding derivatives that were designated and qualified as hedging instruments. The following tables disclose the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, during the three and nine months ended September 30, 2016 (Predecessor) (in millions):

Table of Contents

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended September 30, 2016
(Predecessor)
Derivatives inCash Flow HedgingRelationships	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	$	2.3	Operating revenue - oil/natural gas production	$	7.7	Derivative income (expense), net	$	(0.2	)
Total	$	2.3		$	7.7		$	(0.2	)

(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.

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Nine Months Ended September 30, 2016
(Predecessor)
Derivatives inCash Flow HedgingRelationships	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	$	(1.7	)	Operating revenue - oil/natural gas production	$	29.4	Derivative income (expense), net	$	(0.7	)
Total	$	(1.7	)		$	29.4		$	(0.7	)

(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.

Offsetting of derivative assets and liabilities

Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. The following ~~table~~tables ~~presents~~present the potential impact of the offset rights associated with our recognized assets and liabilities at ~~September~~March 31, 302018 (Successor) and December 31, 2017 (Successor) (in ~~millions~~thousands):

March 31, 2018 (Successor)

As Presented Without Netting

Effects of Netting

With Effects of Netting

Current assets: Fair value of derivative contracts

~~2.6~~417

(~~0.4~~417

)

~~2.2~~—

Long-term assets: Fair value of derivative contracts

~~1.0~~—

~~(0.1~~—

)

~~0.9~~—

Current liabilities: Fair value of derivative contracts

(~~0.4~~13,147

)

~~0.4~~417

—(12,730

)

Long-term liabilities: Fair value of derivative contracts

(~~0.1~~4,564

)

~~0.1~~—

—(4,564

)

We had no outstanding derivative contracts at December 31, 2016 (Predecessor).



	December 31, 2017 (Successor)
	As Presented Without Netting			Effects of Netting			With Effects of Netting
Current assets: Fair value of derivative contracts	$	879		$	(879	)	$	—
Long-term assets: Fair value of derivative contracts	—			—			—
Current liabilities: Fair value of derivative contracts	(8,969		)	879			(8,090		)
Long-term liabilities: Fair value of derivative contracts	(3,085		)	—			(3,085		)

23NOTE 8 – DEBT

~~Table~~Our debt balances (net of ~~Contents~~related unamortized discounts and debt issuance costs) as of March 31, 2018 (Successor) and December 31, 2017 (Successor) were as follows (in thousands):

NOTE 10 – DEBT



	Successor
	March 31, 2018			December 31, 2017
7 ½% Senior Second Lien Notes due 2022	$	225,000		$	225,000
4.20% Building Loan	10,824			10,927
Total debt	235,824			235,927
Less: current portion of long-term debt	(430		)	(425		)
Long-term debt	$	235,394		$	235,502

Our debt balances (net of related unamortized discounts and debt issuance costs) as of September 30, 2017 and December 31, 2016 were as follows (in millions):

	Successor			Predecessor
	September 30,2017			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	11.0			11.3
Total debt	236.0			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	$	235.6		$	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.

Current Portion of Long-Term Debt

As of ~~September~~March 3031, ~~2017~~2018 (Successor), the current portion of long-term debt of $0.4 million represented principal payments due within one year on the 4.20% Building Loan (the “Building Loan”).

~~Successor~~ Revolving Credit Facility

On ~~the~~February ~~Effective Date~~28, ~~pursuant to the terms of the Plan~~2017, the Company entered into the Fifth Amended and Restated Credit Agreement with the lenders party thereto and Bank of America, N.A. (as amended from time to time, 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 reserve-based revolving credit facility and matures on February 28, 2021.

The Company’s ~~available~~borrowing ~~borrowings~~base under the Amended Credit Agreement ~~are~~was ~~set~~redetermined atto $~~150~~100 million ~~until~~on ~~the first borrowing base redetermination in~~ November 8, 2017. On ~~September~~March 3031, ~~2017~~2018, the Company had no outstanding borrowings and $129.68 million of outstanding letters of credit, leaving $~~137~~90.42 million of availability under the Amended Credit Agreement. ~~The borrowing base will be redetermined in early 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.

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. 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. 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 September 30, 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.17

Table of Contents

~~take~~The aborrowing ~~number~~base ~~of actions, including declaring the entire amount then outstanding~~ under the Amended Credit Agreement ~~due~~is ~~and~~redetermined ~~payable.~~semi-annually, ~~The~~in ~~Amended~~May ~~Credit~~and ~~Agreement also requires maintenance of certain financial covenants~~November, ~~including~~by ~~(i) a consolidated funded debt to EBITDA ratio of not more than 2.75x for~~ the ~~test period ending March 31~~lenders, ~~2017,~~in ~~2.50x~~accordance ~~for~~with the ~~test~~lenders’ ~~period~~customary ~~ending~~practices ~~June 30, 2017, 3.00x~~ for ~~the~~oil ~~test~~and ~~period~~gas ~~ending~~loans. ~~September~~In 30addition, ~~2017,~~we ~~2.75x~~and ~~for~~ the ~~test~~lenders ~~period~~each ~~ending~~have ~~December~~discretion ~~31,~~at ~~2017~~any time, ~~2.50x~~but ~~for~~not ~~the~~more ~~test~~than ~~periods~~two ~~ending~~additional ~~March~~times ~~31,~~in ~~2018,~~any ~~June~~calendar 30year, ~~2018,~~to ~~September~~have ~~30,~~the ~~2018~~borrowing ~~and~~base ~~December~~redetermined. ~~31,~~In ~~2018,~~connection ~~respectively,~~with ~~2.75x for~~ the ~~test~~pending ~~period~~Talos ~~ending~~combination, ~~March~~the ~~31,~~May ~~2019~~1, ~~3.00x~~2018 ~~for~~redetermination ~~the~~has ~~test~~been ~~period~~moved ~~ending~~to June 301, ~~2019, 3~~2018.~~50x~~ ~~for~~Subject ~~the~~to ~~test~~certain ~~periods ending September 30~~exceptions, ~~2019~~the ~~and~~Amended ~~December~~Credit ~~31,~~Agreement ~~2019,~~is ~~respectively,~~required ~~3.00x~~to ~~for~~be ~~the~~guaranteed ~~test~~by ~~period~~all ~~ending~~of ~~March 31, 2020, 2.75x for~~ the ~~test~~material ~~periods~~domestic ~~ending~~direct ~~June 30, 2020~~ and ~~September~~indirect ~~30,~~subsidiaries ~~2020,~~of ~~respectively,~~the ~~and 2~~Company.~~50x~~ ~~for~~As ~~the~~of ~~test periods ending December 31, 2020 and~~ March 31, ~~2021~~2018, ~~respectively,~~the ~~(ii)~~Amended aCredit ~~consolidated~~Agreement ~~interest~~is ~~coverage~~guaranteed ~~ratio~~by ofStone ~~not~~Energy ~~less~~Offshore, ~~than 2~~L.~~75 to 1~~L.~~00,~~C. ~~and~~ (~~iii~~“Stone Offshore”). aThe ~~requirement~~Amended toCredit ~~maintain~~Agreement ~~minimum~~is ~~liquidity~~secured ofby atsubstantially ~~least~~all ~~20%~~ of the ~~borrowing~~Company’s ~~base.~~and Weits ~~were~~subsidiaries’ ~~in compliance with all covenants under the Amended Credit Agreement as of September 30, 2017~~assets.

~~Predecessor~~The ~~Revolving~~Amended Credit ~~Facility~~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 certain events of default, the lenders may take a number of actions, including declaring the entire amount then outstanding under the Amended Credit Agreement due and payable (in the event of certain insolvency-related events, the entire amount then outstanding under the Amended Credit Agreement will become automatically 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 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 1.00, and (iii) a requirement to maintain minimum liquidity of at least 20% of the borrowing base. We were in compliance with all covenants under the Amended Credit Agreement as of March 31, 2018.

OnNOTE ~~June 24,~~9 ~~2014,~~– ~~the~~ASSET ~~Predecessor~~RETIREMENT 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 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%.OBLIGATIONS

~~Prior~~The tochange ~~emergence~~in ~~from~~our ~~bankruptcy,~~asset ~~the~~retirement ~~Predecessor~~obligations ~~Company~~during ~~had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit under~~ the ~~Pre-Emergence~~three ~~Credit~~months ~~Agreement. At~~ended ~~emergence~~March 31, ~~the~~2018 ~~outstanding~~(Successor) ~~borrowings~~is ~~were~~set ~~paid~~forth below (in ~~full~~thousands, ~~and~~inclusive ~~the $12.5 million~~ of ~~outstanding~~current ~~letters of credit were converted to obligations under the Amended Credit Agreement.~~portion):

Building Loan



Asset retirement obligations as of January 1, 2018 (Successor)	$	213,101
Liabilities settled	(20,734		)
Accretion expense	4,287
Asset retirement obligations as of March 31, 2018 (Successor)	$	196,654

OnNOTE ~~November~~10 ~~20,~~– ~~2015,~~INCOME 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. As of September 30, 2017, the outstanding balance under the Building Loan totaled $11.0 million.TAXES

~~Successor~~On ~~2022~~December ~~Second~~22, ~~Lien~~2017, ~~Notes~~the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). Generally effective for tax years 2018 and beyond, the Tax Act makes broad and complex changes to the Internal Revenue Code, including, but not limited to, (i) reducing the U.S. federal corporate tax rate from 35% to 21%; (ii) eliminating the corporate alternative minimum tax (“AMT”) and changing how existing AMT credits are realized; (iii) creating a new limitation on deductible interest expense; and (iv) changing rules related to uses and limitation of net operating loss carryforwards created in tax years beginning after December 31, 2017. As of March 31, 2018, we have not completed our accounting for the tax effects of enactment of the Tax Act. However, we have made a reasonable estimate of the effects on our existing deferred tax balances and recognized a provisional amount of $87.3 million to remeasure our deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. This amount is included as a component of income tax expense (benefit) from continuing operations and is fully offset by the related adjustment to our valuation allowance. We are still analyzing certain aspects of the Tax Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.

OnAs ~~the~~a ~~Effective~~result ~~Date,~~of ~~pursuant~~the tosignificant ~~the~~declines ~~terms~~in ofcommodity ~~the~~prices ~~Plan,~~and the ~~Successor~~resulting ~~Company~~ceiling ~~entered~~test ~~into~~write-downs anand ~~indenture~~net bylosses ~~and~~incurred, ~~among~~we ~~the~~determined ~~Company,~~during ~~Stone~~2015 ~~Offshore~~that asit ~~guarantor~~was ~~(the~~more ~~“Guarantor”),~~likely ~~and~~than ~~The~~not ~~Bank~~that a portion of ~~New~~our ~~York~~deferred ~~Mellon~~tax ~~Trust~~assets ~~Company,~~will Nnot be realized in the future.A. Accordingly, aswe ~~trustee~~established ~~and~~a ~~collateral~~valuation ~~agent~~allowance ~~(the~~against ~~“2022~~a ~~Second~~portion ~~Lien~~of ~~Notes~~our ~~Indenture”~~deferred tax assets. As of March 31, 2018 (Successor), ~~and~~our ~~issued~~valuation allowance totaled $~~225~~127.01 million. Our assessment of the ~~Company’s~~realizability ~~2022~~of ~~Second~~our ~~Lien~~deferred ~~Notes~~tax ~~pursuant~~assets ~~thereto~~is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities.

~~Interest~~We onhad ~~the 2022 Second Lien Notes will accrue at~~ a ~~rate~~current ofincome ~~7.50%~~tax ~~per~~receivable ~~annum payable semi-annually in arrears on May 31 and November 30~~ of ~~each year in cash, beginning November 30, 2017. At September 30, 2017,~~ $936.83 million ~~had~~at ~~been~~December ~~accrued in connection with the November 30~~31, 2017 interest payment. 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~~Successor), ~~the~~which ~~security interest in those assets that secure the 2022 Second Lien Notes and the~~ related ~~guarantee will be contractually subordinated~~ to ~~liens~~expected ~~thereon~~tax ~~that~~refunds ~~secure~~from the ~~Company’s~~carryback ~~Amended~~of ~~Credit~~net ~~Agreement~~operating ~~and~~losses ~~certain~~to ~~other~~previous ~~permitted~~tax ~~obligations~~years. asIn ~~set~~January ~~forth~~2018, inwe ~~the~~received ~~2022 Second Lien Notes Indenture~~$20.1 ~~Consequently,~~million ~~the~~of ~~2022 Second Lien Notes and~~ the ~~related~~tax ~~guarantee~~refund ~~will be effectively subordinated to the Amended Credit Agreement~~ and ~~such~~have ~~other~~a ~~permitted~~current ~~secured~~income ~~indebtedness~~tax toreceivable ~~the extent~~ of ~~the~~$16.2 ~~value~~million ofat ~~such~~March 31, ~~assets~~2018 (Successor).

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 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.18

Table of Contents

~~The~~NOTE ~~2022~~11 ~~Second~~– ~~Lien~~FAIR ~~Notes~~VALUE 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.MEASUREMENTS

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 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. On June 10, 2016, we completed a 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 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 Plan, the $300 million of debt related to the 2017 Convertible Notes was cancelled. See Note 2 – Reorganization for additional details.

During the three and nine months ended September 30, 2016 (Predecessor), we recognized $4.1 million and $12.0 million, respectively, of interest expense for the amortization of the discount, $0.4 million and $1.1 million, respectively, of interest expense for the amortization of deferred financing costs and $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, 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.

Table of Contents

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 September 30, 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	(53.1		)
Accretion expense	19.7
Revision of estimates	11.0
Asset retirement obligations as of September 30, 2017 (Successor)	$	267.6

NOTE 12 – 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, 2017 (Successor), our valuation allowance totaled $236.7 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 $27.7 million at September 30, 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 ~~September~~March 3031, ~~2017~~2018 (Successor) and December 31, ~~2016~~2017 (~~Predecessor~~Successor), 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 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 97 – 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.

27The following tables present our assets and liabilities that are measured at fair value on a recurring basis at March 31, 2018 (Successor) (in thousands).



	Fair Value Measurements
	Successor as of
	March 31, 2018
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)	$	4,964	$	4,964	$	—	$	—
Derivative contracts	417		—		—		417
Total	$	5,381	$	4,964	$	—	$	417



	Fair Value Measurements
	Successor as of
	March 31, 2018
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative contracts	$	17,711	$	—	$	15,330	$	2,381
Total	$	17,711	$	—	$	15,330	$	2,381

Table of Contents

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at ~~September~~December 3031, 2017 (Successor) (in ~~millions~~thousands).

Fair Value Measurements

Successor as of

September 30, 2017

December 31, 2017

Assets

Total

Quoted Pricesin ActiveMarkets ~~forIdentical Assets~~forIdenticalAssets(Level 1)

SignificantOtherObservableInputs(Level 2)

SignificantUnobservableInputs(Level 3)

Marketable securities (Other assets)

~~9.3~~5,081

—

Derivative contracts

~~3.6~~879

—

~~0.5~~—

~~3.1~~879

Total

~~12.9~~5,960

~~9.3~~5,081

~~0.5~~—

~~3.1~~879

Fair Value Measurements at

Fair Value Measurements

Successor as of

September 30, 2017

December 31, 2017

Liabilities

Total

Quoted Pricesin ActiveMarkets forIdenticalLiabilities(Level 1)

SignificantOtherObservableInputs(Level 2)

SignificantUnobservableInputs(Level 3)

Derivative contracts

~~0.5~~12,054

—

~~0.1~~10,110

~~0.4~~1,944

Total

~~0.5~~12,054

—

~~0.1~~10,110

~~0.4~~1,944

WeThe ~~had~~table nobelow presents a reconciliation for assets and liabilities measured at fair value on a recurring basis atusing ~~December~~significant ~~31,~~unobservable ~~2016~~inputs (~~Predecessor~~Level 3). ~~The~~during ~~following~~the ~~table~~three ~~presents~~months ~~our~~ended ~~assets that are measured at fair value on a recurring basis at December~~March 31, ~~2016~~2018 (~~Predecessor~~Successor) (in ~~millions~~thousands).

	Fair Value Measurements
		Hedging Contracts, net
	Predecessor as of
Balance as of January 1, 2018 (Successor)		$	(1,065	)
	December 31, 2016
Total gains/(losses) (realized or unrealized):
Assets	Total				Quoted Pricesin ActiveMarkets forIdenticalAssets(Level 1)		SignificantOtherObservableInputs(Level 2)		SignificantUnobservableInputs(Level 3)
Included in earnings		(1,579		)
Marketable securities (Other assets)	$	8.7			$	8.7	$	—	$	—
Included in other comprehensive income		—
Total	$	8.7			$	8.7	$	—	$	—
Purchases, sales, issuances and settlements		680
Transfers in and out of Level 3		—
Balance as of March 31, 2018 (Successor)		$	(1,964	)
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, 2018		$	(4,702	)

28The fair value of cash and cash equivalents approximated book value at March 31, 2018 and December 31, 2017. As of March 31, 2018 and December 31, 2017, the fair value of the 2022 Second Lien Notes was approximately $229.5 million and $227.3 million, respectively. The fair value of the 2022 Second Lien Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs.

Table of Contents

The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period from March 1, 2017 through September 30, 2017 (Successor) and the period from January 1, 2017 through February 28, 2017 (Predecessor) (in millions).

	Hedging Contracts, net
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	(1.3		)
Included in other comprehensive income	—
Purchases, sales, issuances and settlements	1.0
Transfers in and out of Level 3	—
Balance as of September 30, 2017 (Successor)	$	2.8
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, 2017	$	(1.7	)

The fair value of cash and cash equivalents approximated book value at September 30, 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 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 September 30, 2017, the fair value of the 2022 Second Lien Notes was approximately $220.5 million.

The fair values of the 2022 Notes and the 2022 Second Lien Notes were 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.

2920

Table of Contents

NOTE 1412 – ~~ACCUMULATED~~COMBINATION ~~OTHER~~TRANSACTION ~~COMPREHENSIVE INCOME (LOSS)~~COSTS

~~Through~~In ~~December~~connection ~~31,~~with ~~2016~~the pending combination with Talos, we ~~designated~~incurred ~~our~~approximately ~~commodity~~$3.4 ~~derivatives~~million asin ~~cash~~transaction ~~flow~~costs ~~hedges~~during ~~for~~the ~~accounting~~three ~~purposes~~months ~~upon~~ended ~~entering~~March ~~into~~31, ~~the~~2018 ~~contracts,~~(Successor). These costs consist primarily of legal and ~~accordingly,~~financial ~~changes~~advisor costs and are included in ~~the~~salaries, ~~fair~~general ~~value~~and ofadministrative ~~the~~(“SG&A”) ~~derivative~~expense ~~were~~on ~~recognized~~our instatement ~~stockholders’~~of ~~equity~~operations ~~through~~for ~~other~~the ~~comprehensive~~three ~~income~~months ended March 31, 2018 (~~loss~~Successor). Additionally, ~~net~~we have incurred approximately $0.2 million of ~~related~~direct ~~taxes,~~costs for purposes of registering equity securities to effect the ~~extent~~Talos ~~the~~combination. ~~hedge~~These ~~was~~direct ~~considered~~costs ~~effective~~were recorded as a reduction of additional paid-in-capital during 2017. WeSee ~~had~~Note no1 ~~outstanding~~– ~~derivative~~Financial ~~contracts~~Statement atPresentation ~~December~~(Pending ~~31,~~Combination ~~2016~~with Talos) for more information on the pending combination.

~~During~~NOTE ~~the~~13 ~~periods from March 1, 2017 through September 30, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor), we entered into various commodity derivative contracts (see Note 9~~ – ~~Derivative~~REVENUE Instruments and Hedging Activities). With respect to our 2017, 2018 and 2019 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).RECOGNITION

~~Changes~~Our inmajor ~~accumulated~~sources ~~other~~of ~~comprehensive~~revenue ~~income~~are oil, natural gas and NGL production from our oil and gas properties. We sell crude oil to purchasers typically through monthly contracts, with the sale taking place at the wellhead. Natural gas is sold to purchasers through monthly contracts, with the sale taking place at the wellhead or the tailgate of an onshore gas processing plant (~~loss~~after the removal of NGLs). byWe ~~component~~actively market our crude oil and natural gas to purchasers and the volumes are metered and therefore readily determinable. Sales prices for purchased oil and natural gas volumes are negotiated with purchasers and are based on certain published indices. Since the ~~three~~oil and ~~nine~~natural ~~months~~gas ~~ended~~contracts ~~September~~are 30month-to-month, ~~2016~~there is no dedication of production to any one purchaser. We sell the NGLs entrained in the natural gas that we produce. The arrangements to sell these products first requires natural gas to be processed at an onshore gas processing plant. Once the liquids are removed and fractionated (~~Predecessor~~broken into the individual hydrocarbon chains for sale), ~~were~~the products are sold by the processing plant. The residue gas left over is sold to natural gas purchasers as ~~follows~~natural gas sales (inreferenced ~~millions~~above):. The contracts for NGL sales are with the processing plant. The prices received for the NGLs are not negotiated by the Company, but rather, are based on what the processing plant can receive from a third party purchaser. The gas processing and subsequent sales of NGLs are subject to contracts with longer terms and dedications of lease production from the Company’s leases offshore.

	Cash FlowHedges
Three Months Ended September 30, 2016 (Predecessor)
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

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. See Note 1 – Financial Statement Presentation (Recently Adopted Accounting Standards). We adopted ASU 2014-09 on January 1, 2018 using the modified retrospective approach, with the cumulative effect of initially applying the new standard as an adjustment to accumulated deficit on the date of initial application. We applied the standard to contracts in place during 2017 and to new contracts entered into after January 1, 2018. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows.

	Cash FlowHedges			ForeignCurrencyItems			Total
Nine Months Ended September 30, 2016 (Predecessor)
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

We have historically recognized oil, natural gas and NGL production revenue under the entitlements method of accounting. Under this method, revenue was deferred for deliveries in excess of our net revenue interest, while revenue was accrued for undelivered or underdelivered volumes (production imbalances). Production imbalances were generally recorded at the estimated sales price in effect at the time of production. ASU 2014-09 effectively eliminated the entitlements method of accounting, requiring us instead to recognize production revenue for the quantities and values of oil, natural gas and NGLs delivered or received. Our aggregate imbalance positions at December 31, 2017 were immaterial and required only a $0.7 million cumulative effect adjustment (all of which related to oil production) to the January 1, 2018 opening balance of our accumulated deficit upon adoption of ASU 2014-09.

~~During~~Sales of oil, natural gas and NGLs are recognized when the ~~nine~~product is delivered and title transfers to the purchaser. Payment is generally received one to three months ~~ended~~after ~~September~~the 30sale has occurred. To the extent actual quantities and values of oil, ~~2016~~natural gas and NGL production for properties are not available for a given reporting period because of timing or information not received from the purchasers, the expected sales volumes and price are estimated and the result is recorded as purchaser accounts receivable (~~Predecessor~~included in Accounts Receivable) in our balance sheet and as Oil, Natural Gas and NGL production revenue in our statement of operations. At March 31, 2018 (Successor), we ~~reclassified~~recorded a purchaser accounts receivable of $631.02 million, ~~loss~~consisting ~~related~~of to$25.5 ~~cumulative~~million ~~foreign~~of ~~currency~~oil ~~translation~~production ~~adjustments~~revenue, ~~from~~$3.5 ~~accumulated~~million ~~other~~of ~~comprehensive~~natural ~~income~~gas ~~into~~production ~~other~~revenue ~~operational~~and ~~expenses~~$2.2 ~~upon~~million ~~the~~of ~~substantial~~NGL ~~liquidation~~production revenue. At December 31, 2017 (Successor), we recorded a purchaser accounts receivable of ~~our~~$32.8 ~~foreign~~million, ~~subsidiary~~consisting of $26.7 million of oil production revenue, ~~Stone~~$3.9 ~~Energy~~million ~~Canada~~of ~~ULC~~natural gas production revenue and $2.2 million of NGL production revenue. Revenue proceeds relating to third-party royalty owners not remitted by the end of a reporting period are recorded as Undistributed Oil and Gas Proceeds in our balance sheet.

30NOTE 14 – PRODUCTION TAXES

Production taxes for the three months ended March 31, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor) totaled ($2.2) million, $0.1 million and $0.7 million, respectively. During the three months ended March 31, 2018, we received a $2.4 million refund related to previously paid severance taxes in West Virginia.

Table of Contents

NOTE 15 – ~~FEDERAL~~COMMITMENTS ~~ROYALTY~~AND ~~RECOVERY~~CONTINGENCIES

InLegal July 2017, we received a federal royalty recovery totaling $14.1 million as part of a multi-year federal royalty refund claim. Approximately $9.6 million of the refund was recognized as other operational income and $4.5 million as a reduction of lease operating expenses during the three months ended September 30, 2017 (Successor). Included in SG&A expenses during the three months ended September 30, 2017 (Successor) is a $3.9 million success-based consulting fee incurred in connection with the federal royalty recovery.Proceedings

~~NOTE~~We 16are –named ~~REDUCTION~~as INa ~~WORKFORCE~~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.

~~During~~Other ~~the~~Commitments second quarter of 2017, we implemented workforce reduction plans to better align our employee base with current business needs, resulting in a reduction of approximately 20% of our total workforce. The workforce reductions were complete as of July 31, 2017. In connection with the reductions, we recognized a charge of $5.7 million during the three months ended June 30, 2017 (Successor), consisting primarily of severance payments to affected employees and payment of related employer payroll taxes. This charge is reflected in SG&A expenses on the statement of operations. Approximately $4.5 million of the workforce reduction costs were paid in cash during the second quarter of 2017. At June 30, 2017, we recorded a liability of $1.2 million for severance payments and related employer payroll taxes. The liability was fully paid in July 2017.Contingencies

InOn ~~addition~~March to21, ~~the~~2016, ~~workforce~~we ~~reduction~~received ~~costs,~~notice ~~during~~letters from the ~~three~~Bureau ~~months~~of ~~ended~~Ocean ~~June~~Energy ~~30,~~Management ~~2017~~ (~~Successor~~“BOEM”), stating that BOEM had determined that we ~~recognized~~no longer qualified for a ~~charge~~supplemental ofbonding $3waiver under the financial criteria specified in BOEM’s guidance to lessees at such time.0 In ~~million~~late March 2016, we proposed a tailored plan to BOEM for ~~severance~~financial ~~costs~~assurances ~~related~~relating to ~~the~~our ~~sale~~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 ~~Appalachia~~understanding ~~Properties~~that we will continue to make progress with BOEM towards finalizing and ~~the~~implementing ~~retirement~~our long-term tailored plan. As of ~~the~~March ~~prior~~31, ~~chief~~2018, ~~executive~~we ~~officer~~have ofposted ~~the~~an ~~Company.~~aggregate ~~These~~of ~~severance~~approximately ~~costs~~$115 ~~are~~million ~~reflected~~in surety bonds in ~~SG&A~~favor ~~expenses~~of onBOEM, ~~the~~third-party ~~statement~~bonds and letters of ~~operations~~credit, all relating to our offshore abandonment obligations.

~~NOTE~~In 17July –2016, ~~OTHER~~BOEM ~~OPERATIONAL~~issued ~~EXPENSES~~a Notice to Lessees (the “NTL”), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL details procedures to determine a lessee’s ability to carry out its lease obligations (primarily the decommissioning of facilities on the Outer Continental Shelf (“OCS”)) and whether to require lessees to furnish additional financial assurances to meet BOEM’s estimate of the lessees decommissioning obligations. The NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The NTL also allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances.

~~Other~~We ~~operational~~received ~~expenses~~a ~~for~~self-insurance ~~the~~letter ~~period~~ from ~~March~~BOEM 1,dated ~~2017 through~~ September 30, ~~2017~~2016 ~~(Successor)~~stating ~~totaled~~that ~~$3.3~~we ~~million,~~were ~~comprised~~not ~~primarily~~eligible ofto ~~$2.1~~self-insure ~~million~~any of ~~stacking~~our ~~charges~~additional ~~related~~security ~~to the platform rig at Pompano, while awaiting demobilization~~obligations. ~~Other~~We ~~operational~~received ~~expenses for the nine months ended September 30, 2016 (Predecessor) totaled $49.3 million. Included in other operational expenses for the nine months ended September 30, 2016 (Predecessor) is~~ a ~~$6.0~~proposal ~~million~~letter ~~loss~~from onBOEM ~~the~~dated ~~substantial liquidation of our foreign subsidiary~~October 20, ~~Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income during the first quarter of~~ 2016. ~~See~~indicating ~~Note~~that 14additional –security ~~Accumulated~~may ~~Other~~be ~~Comprehensive Income (Loss)~~required. ~~Also~~ ~~included~~The ~~in other operational expenses for the nine months ended~~ September 30, 2016 ~~(Predecessor)~~self-insurance ~~are~~determination ~~$15.3~~letter ~~million~~was ofrescinded ~~rig~~by ~~subsidy~~BOEM ~~and~~on ~~stacking charges related to the ENSCO 8503 deep water drilling rig~~March 24, ~~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~~2017.5 ~~million of charges related to the terminations of the Appalachian drilling rig contract and a contract with an offshore vessel provider.~~

~~NOTE~~In 18the –first ~~COMMITMENTS~~quarter ~~AND~~of ~~CONTINGENCIES~~2017, BOEM announced that it would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. At this time, it is uncertain when the July 2016 NTL will be implemented as a revised NTL. A revised tailored plan may require incremental financial assurance or bonding for non-sole liability properties, dependent on adjustments following ongoing discussions with BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”), and any modifications to the proposed NTL. There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan.

OnNOTE ~~March~~16 ~~21,~~– ~~2016,~~SUBSEQUENT 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. EVENTS

InOn ~~July~~May ~~2016~~1, ~~BOEM issued a Notice to Lessees (“NTL”)~~2018, ~~with~~Stone ancompleted ~~effective~~the ~~date~~acquisition of ~~September~~a ~~12,~~100% ~~2016,~~working ~~that~~interest ~~augments~~in ~~requirements for~~ the ~~posting~~Ram ofPowell ~~additional~~Unit, ~~financial~~including ~~assurances~~six bylease ~~offshore~~blocks ~~lessees.~~in ~~The~~the ~~NTL~~Viosca ~~discontinues~~Knoll Area, the ~~policy~~Ram ofPowell ~~Supplemental~~tension ~~Bonding~~leg ~~Waivers~~platform (“TLP”), and ~~allows~~related ~~for~~assets, ~~the~~from ~~ability~~Shell toOffshore ~~self-insure~~Inc., upExxon toMobil ~~10%~~Corporation, ofand aAnadarko ~~company’s~~US ~~tangible~~Offshore ~~net worth~~LLC, ~~where~~for a ~~company~~purchase ~~can~~price ~~demonstrate~~of a$34 ~~certain~~million, ~~level~~with ofan ~~financial~~effective ~~strength. The~~date ~~NTL~~of ~~also~~October ~~provides~~1, ~~new~~2017, ~~procedures~~and ~~for~~the ~~how~~posting ~~BOEM~~of ~~determines~~decommissioning asurety ~~lessee’s~~bonds ~~decommissioning~~of ~~obligations~~$200 million. AAfter ~~global~~considering ~~update of~~ the ~~GOM~~effects ~~decommissioning~~of ~~estimates~~customary ~~was~~purchase ~~made~~price onadjustments ~~August~~from ~~29,~~the ~~2016,~~effective ~~and~~date ~~BOEM~~of ~~requested~~the ~~that~~acquisition wethrough ~~resubmit~~closing, ~~our~~Stone ~~tailored~~received ~~plan~~net tocash ~~reflect~~of ~~the~~$29.4 ~~updated~~million ~~decommissioning~~at ~~estimates~~closing.

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 and received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required. 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 would extend the implementation timeline for the new NTL by an additional six months. In September 2017, BOEM again postponed any implementation of the July 2016 NTL, and has indicated they may be issuing a modified or substitute NTL in late 2017.22

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. 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

Table of Contents

specified by applicable working interest purchase and sale agreements. A revised tailored plan may require incremental financial assurance or bonding for non-sole liability properties, dependent on adjustments following ongoing discussions with BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”), and any modifications to the proposed NTL. There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan.

NOTE 19 – NEW YORK STOCK EXCHANGE COMPLIANCE

On May 17, 2016, we were notified by the New York Stock Exchange (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. On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity deficiencies to the NYSE, and on August 4, 2016, the NYSE accepted the Plan. All of our quarterly updates to the business plan were 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.

On August 24, 2017, we were notified by the NYSE that we are back in compliance with their continued listing standards as a result of the Company’s consistent positive performance with respect to the original business plan submission and the achievement of compliance with the average global market capitalization and stockholders’ equity listing requirements over the past two quarters. In accordance with the NYSE’s Listed Company Manual, we will be subject to a 12-month follow up period within which the Company will be reviewed to ensure that the Company does not fall below any of the NYSE’s continued listing standards.

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this “Form 10-Q”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements as described in our ~~2016~~2017 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~~activities;


•	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, including the Board’s assessment of the Company’s strategic direction.;


•	our ability to consummate our proposed combination transaction with Talos; and


•	the timing of the consummation of the proposed combination transaction with Talos.

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


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


•	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;


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


•	the potential need to 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;

• declines in the value of our oil and gas properties resulting in a decrease in ~~our~~the 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;

Table of Contents


•	regulatory and environmental risks associated with drilling and production 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;

Table of Contents


•	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;


•	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 and our ~~2016~~2017 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 ~~2016~~2017 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our ~~2016~~2017 Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contained in this Form 10-Q should be read in conjunction with the MD&A contained in our ~~2016~~2017 Annual Report on Form 10-K.

Critical Accounting Policies and Estimates

Our ~~2016~~2017 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;


•	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 ~~2016~~2017 Annual Report on Form 10-K regarding ~~these~~our critical accounting policies and estimates. There have been no material changes to our critical accounting policies from those described in our ~~2016~~2017 Annual Report on Form 10-K~~, except as described below~~.

~~Fresh~~See ~~Start~~Part ~~Accounting~~I, Item 1. Financial Statements – Note 13 – Revenue Recognition for details on changes in Stone’s revenue recognition policy as a result of the adoption of ASU 2014-09, effective January 1, 2018. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows, but did result in increased disclosures related to revenue recognition policies and disaggregation of revenues.

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.

Table of Contents

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, 2018 and 2019 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 ~~2016~~2017 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.

Table of Contents

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 Gulf of Mexico (“GOM”) Basin since our incorporation in 1993 and have established technical and operational expertise in this area. We leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific ~~basins~~plays of the GOM deep water, and Gulf Coast deep gas ~~and the Marcellus and Utica shales in Appalachia~~. At December 31, 2016, we had producing properties and acreage in the Marcellus and Utica Shales in Appalachia. In connection with our restructuring efforts, we determined that a 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 cash consideration of approximately $522.5 million. See “Reorganization and Emergence from Voluntary Chapter 11 Proceedings” below for additional information on the sale of the Appalachia Properties.

As discussed in Part I, Item 1. Financial Statements – Note 3 – Fresh Start Accounting, upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of ASC 852, “Reorganizations”, which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. 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 a result of the 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. 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.

Pending Combination with Talos

On November 21, 2017, Stone entered into a Transaction Agreement to combine with Talos in an all-stock transaction. Under the terms of the Transaction Agreement, each outstanding share of Stone common stock will be exchanged for one share of New Talos common stock and the current Talos stakeholders (including the Apollo Funds and the Riverstone Funds) will be issued an aggregate of approximately 34.1 million shares of New Talos common stock. After the completion of the Transactions contemplated by the Transaction Agreement, holders of Stone common stock immediately prior to the combination will collectively hold 37% of the outstanding New Talos common stock and Talos Energy stakeholders will hold 63% of the outstanding New Talos common stock. Outstanding warrants to acquire Stone common stock will become warrants to acquire New Talos common stock with terms and conditions substantially identical to their existing terms and conditions. The combination was unanimously approved by the boards of directors of Stone and Talos Energy.

On March 20, 2018, the Talos Issuers launched an offer to exchange Stone’s outstanding 2022 Second Lien Notes for newly issued 11.0% second lien notes due 2022 of the Talos Issuers. Concurrently with the Exchange Offer, the Talos Issuers solicited and received sufficient consents from holders of the 2022 Second Lien Notes to amend certain terms of the Stone Notes Indenture and to release the collateral securing the 2022 Second Lien Notes.

The combination is expected to close on or about May 10, 2018. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all. The above is a summary of the material terms of the Transactions and is qualified in its entirety by reference to the New Talos Registration Statement on Form S-4 (which became effective on April 9, 2018). See Part I, Item 1. Financial Statements – Note 1 – Financial Statement Presentation (Pending Combination with Talos) for additional information on the pending combination.

Reorganization and Emergence from Voluntary Chapter 11 Proceedings

On December 14, 2016, we filed ~~Bankruptcy~~voluntary ~~Petitions~~petitions seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code to pursue a prepackaged plan of reorganization to address our liquidity and capital structure. On February 1528, 2017, the ~~Bankruptcy~~Plan ~~Court~~became ~~entered~~effective anand ~~order~~we ~~confirming~~emerged ~~the~~from ~~Plan~~bankruptcy. In connection with our reorganization, ~~and~~we sold our Appalachia Properties on February 2827, 2017, for net cash consideration of approximately $522.5 million. Upon closing of the ~~Plan~~sale ~~became~~on ~~effective~~February ~~and~~27, 2017, we ~~emerged~~no longer have operations or assets in Appalachia. A portion of the consideration received from ~~bankruptcy~~the sale of the Appalachia Properties was used to fund the Company’s cash payment obligations under the Plan.

InUpon ~~connection~~emergence ~~with~~from ~~our restructuring efforts~~bankruptcy, wepursuant ~~sold our Appalachia Properties~~ to ~~EQT~~the onterms ~~February 27, 2017, for net cash consideration~~ of ~~approximately~~the ~~$522.5 million~~Plan, ~~representing~~the ~~gross~~Predecessor ~~proceeds~~Company’s of2022 ~~$527.0~~Notes ~~million~~and ~~adjusted~~2017 ~~downward~~Convertible byNotes ~~approximately~~were ~~$4.5~~cancelled ~~million~~and ~~for~~the ~~purchase~~holders ~~price~~of ~~adjustments~~such ~~for~~notes ~~operations~~received ~~related~~their topro ~~the~~rata ~~Appalachia~~share ~~Properties~~of ~~after~~$100 ~~June~~million 1,of ~~2016~~cash, ~~the effective date of the transaction~~19.0 Amillion ~~portion~~shares of the ~~consideration~~New ~~received~~Common ~~from~~Stock ~~the~~(representing ~~sale~~95% of the ~~Appalachia~~New ~~Properties~~Common ~~was~~Stock) ~~used~~and to$225 ~~fund~~million ~~the~~of ~~Company’s~~2022 ~~cash~~Second ~~payment~~Lien ~~obligations under the Plan~~Notes. AtThe ~~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 Appalachia.~~

~~Upon emergence from bankruptcy, pursuant to the terms of the Plan, the following significant transactions occurred:~~25

• 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 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.

Table of Contents

Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement. 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. See Liquidity and Capital Resources below for additional information on the Successor Company’s debt instruments.

•Operational ~~The~~Update Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement. The obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement.

•On ~~All~~May ~~claims~~1, 2018, Stone completed the acquisition of ~~creditors~~a 100% working interest in the Ram Powell Unit, including six lease blocks in the Viosca Knoll Area, the Ram Powell TLP, and related assets, from Shell Offshore Inc., Exxon Mobil Corporation, and Anadarko US Offshore LLC, for a purchase price of $34 million, with ~~unsecured~~an ~~claims~~effective date of October 1, ~~other~~2017, ~~than~~and the ~~claims~~posting byof decommissioning surety bonds of $200 million. After considering the ~~holders~~effects of customary purchase price adjustments from the ~~2022~~effective ~~Notes~~date ~~and~~of ~~2017~~the ~~Convertible~~acquisition ~~Notes~~through closing, ~~including~~Stone ~~vendors~~received net cash of $29.4 million at closing. Production for the Ram Powell field averaged approximately 6,100 ~~were~~Boe ~~unaltered~~per ~~and~~day ~~paid~~during 2017. The Ram Powell TLP is located in ~~full~~3,200 feet of water in ~~the~~Viosca ~~ordinary~~Knoll ~~course~~Area, Block 956 and is capable of ~~business~~producing to60,000 ~~the~~barrels ~~extent~~of ~~the~~oil ~~claims~~per ~~were~~day ~~undisputed~~and 200 million cubic feet of gas per day, which could allow for potential processing of additional third party production.

~~For~~The ~~further~~Derbio ~~information~~exploration ~~regarding~~well (Mississippi Canyon Block 72 #3 well) reached total depth in April 2018 and encountered reservoir-quality sands in the ~~debt~~targeted ~~instruments~~objective that did not contain commercial saturations of hydrocarbons. The partners are now evaluating the ~~Successor~~possible ~~Company,~~development ~~see~~of ~~Liquidity~~the ~~and~~Rampart ~~Capital~~Deep ~~Resources~~well ~~below~~as a single-well tieback. Stone has a 40% working interest in the Derbio well.

~~Management~~Completion ~~Changes~~operations on the Mt. Providence well, located in Mississippi Canyon Block 28, are currently expected to commence in June or July 2018, with first production expected in the third quarter of 2018. The well will be tied back to the Pompano platform through existing subsea infrastructure. Stone has a 100% working interest in the Mt. Providence well.

On April 25, 2017, David H. Welch informed the Board of his intention to retire as the Chief Executive Officer and President of the Company and as a member of the Board. Effective April 28, 2017, the Board elected James M. Trimble, a member of the Board, to serve as the 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 Company’s Chief Operating Officer.

Strategic Review

Following the successful completion of our financial restructuring and emergence from Chapter 11 reorganization, the Board retained a financial advisor in April 2017 to assist the Board in its determination of the Company’s strategic direction, including assessing its various strategic alternatives. The Board’s assessment with its financial advisor is ongoing. There can be no assurance that this assessment will result in any transaction.

Known Trends and Uncertainties

~~Non-designation~~Commodity ofDerivative ~~Commodity~~Income ~~Derivatives~~(Expense) – ~~With~~We ~~respect~~account ~~to our 2017, 2018 and 2019 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 – If NYMEX commodity prices remain at current levels (approximately $52.00 per Bbl of oil and $3.00 per MMBtu of natural gas), we would expect an increase in the 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 a ceiling test write-down in the fourth quarter of 2017. However, significant evaluations or impairments of unevaluated costs or other well performance related activities affecting proved reserve quantities could cause us to recognize such a write-down.

BOEM Financial Assurance Requirements – 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 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.

In July 2016, BOEM issued ana 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~~details procedures to determine a lessee’s ability to carry out its lease obligations (primarily the ~~policy~~decommissioning of ~~Supplemental~~OCS ~~Bonding~~facilities) ~~Waivers~~ and ~~allows~~whether ~~for~~to ~~the~~require ~~ability~~lessees to ~~self-insure~~furnish upadditional financial assurances to ~~10%~~meet BOEM’s estimate of athe ~~company~~lessees decommissioning obligations. The NTL supersedes the agency’s ~~tangible~~prior ~~net~~practice ~~worth,~~of ~~where~~allowing operators of a ~~company~~certain ~~can~~net ~~demonstrate~~worth ato ~~certain~~waive ~~level~~the ofneed ~~financial~~for ~~strength. The~~supplemental ~~NTL~~bonds ~~also~~and provides ~~new~~updated ~~procedures~~criteria for ~~how~~determining ~~BOEM determines~~ a lessee’s ~~decommissioning~~ability ~~obligations.~~to Aself-insure ~~global~~only ~~update~~a small portion of its OCS liabilities based upon the ~~GOM~~lessee’s ~~decommissioning~~financial ~~estimates~~capacity ~~was~~and ~~made~~financial onstrength. ~~August~~The ~~29,~~NTL ~~2016,~~also ~~and~~allows ~~BOEM~~lessees ~~requested~~to ~~that~~meet wetheir ~~resubmit~~additional ~~our~~financial security requirements pursuant to an individually approved tailored plan, whereby an operator and BOEM agree to ~~reflect~~set a timeframe for the ~~updated~~posting ~~decommissioning~~of ~~estimates.~~additional financial assurances.

36We received a self-insurance letter from BOEM dated September 30, 2016 stating that we were 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. 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 would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline

Table of Contents

Wewould ~~received~~be aindefinitely ~~Self-Insurance~~extended, ~~letter~~subject ~~from~~to ~~BOEM~~certain ~~dated~~exceptions. ~~September~~At 30this time, ~~2016~~it ~~stating~~is ~~that~~uncertain wewhen ~~are~~the ~~not~~July ~~eligible~~2016 toNTL ~~self-insure~~will ~~any~~be ofimplemented ~~our~~as ~~additional~~a ~~security~~revised ~~obligations~~NTL. ~~and~~Compliance ~~received~~with athe ~~Proposal~~NTL, ~~letter~~or ~~from~~any ~~BOEM~~other ~~dated~~new ~~October~~rules, 20regulations, ~~2016~~or ~~indicating~~legal ~~that~~initiatives ~~additional~~by ~~security~~BOEM ~~may~~or beother ~~required. The~~governmental ~~September~~authorities ~~30,~~that ~~2016~~impose ~~Self-Insurance~~more ~~determination~~stringent ~~letter~~requirements ~~was~~adversely ~~rescinded~~affecting byour ~~BOEM~~offshore onactivities ~~March~~could ~~24,~~delay ~~2017.~~or Indisrupt ~~the~~our ~~first quarter of 2017~~operations, ~~BOEM~~result ~~announced~~in ~~that~~increased itsupplemental ~~would~~bonding ~~extend~~and ~~the~~costs, ~~implementation~~limit ~~timeline~~our ~~for~~activities ~~the~~in ~~new~~certain ~~NTL~~areas, bycause anus ~~additional~~to ~~six~~incur ~~months.~~penalties Inor ~~September~~fines ~~2017,~~or ~~BOEM~~to shut-in production ~~again~~at ~~postponed~~one ~~any~~or ~~implementation~~more of ~~the~~our ~~July 2016 NTL~~facilities, ~~and~~or ~~has~~result ~~indicated~~in ~~they~~the ~~may~~suspension ~~be issuing a modified~~ or ~~substitute~~cancellation ~~NTL~~of ~~in late 2017~~leases.

~~Currently~~As of March 31, 2018, we have posted an aggregate of approximately $~~118~~115 million in surety bonds in favor of BOEM, third -party bonds and letters of credit, all relating to our offshore abandonment obligations. In conjunction with the acquisition of the Ram Powell field on May 1, 2018 (see Part I, Item 1. Financial Statements – Note 16 – Subsequent Events), we have posted an additional $200 million in surety bonds. 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. There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. A revised tailored plan may require incremental financial assurance or bonding for non-sole liability properties, dependent on adjustments following ongoing discussions with BOEM and BSEE, and any modifications to the proposed NTL. ~~There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan.~~

Hurricanes – Since a large portion of our production originates from 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 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 an incident 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

InAs ~~connection~~of ~~with~~May 7, ~~our restructuring efforts~~2018, we ~~sold~~had ~~our~~approximately ~~Appalachia~~$295 ~~Properties~~million onof ~~February 27, 2017 for net~~ cash ~~consideration~~on ofhand ~~approximately~~and $~~522~~90.52 million. ~~A portion~~ of ~~the~~availability ~~consideration received from the sale of the Appalachia Properties was used to fund the Company’s cash payment obligations~~ under the ~~Plan.~~Amended ~~Upon~~Credit ~~emergence from bankruptcy on February 28~~Agreement, ~~2017,~~and ~~we eliminated approximately~~ $1235.17 ~~billion~~million in ~~principal~~total ~~amount of~~ debt. ~~For additional details~~outstanding, ~~see~~including ~~“Reorganization~~$225 ~~and~~million ~~Emergence~~of ~~from~~2022 ~~Voluntary~~Second ~~Chapter~~Lien 11Notes ~~Proceedings”~~and ~~above~~$10.7 ~~These~~million ~~significant~~outstanding ~~transactions~~under ~~improved~~the ~~our~~Building ~~financial position and liquidity~~Loan.

AsIn ofJanuary ~~November 1~~2018, ~~2017,~~the weBoard ~~had~~authorized ~~approximately~~a ~~$242~~2018 ~~million~~capital ofexpenditure ~~cash~~budget onof ~~hand~~up ~~and~~to $38212 million, ofwhich ~~cash~~excludes ~~held~~acquisitions inand acapitalized ~~restricted~~SG&A ~~account~~and tointerest, ~~satisfy near-term plugging~~ and ~~abandonment~~does ~~liabilities,~~not ~~pursuant~~give effect to the ~~terms~~potential ofTalos ~~the~~combination. ~~Amended~~The ~~Credit~~budget ~~Agreement,~~is ~~and~~spread ~~$236~~across ~~million~~Stone's inmajor ~~total~~areas ~~debt~~of ~~outstanding~~investment, ~~including~~with ~~$225~~approximately ~~million~~36% ofallocated ~~2022~~to ~~Second~~exploration, ~~Lien~~27% ~~Notes~~to development, and ~~$11~~37% ~~million~~to ~~outstanding~~plugging ~~under~~and ~~the~~abandonment ~~Building Loan~~expenditures. ~~Our~~The ~~available~~allocation ~~borrowings~~of ~~under~~capital across the ~~Amended~~various ~~Credit~~areas ~~Agreement~~is ~~are~~subject ~~set~~to atchange ~~$150~~based ~~million~~on ~~until~~several ~~the~~factors, ~~first~~including ~~borrowing~~permitting ~~base~~times, ~~redetermination~~rig availability, non-operator decisions, farm-in ~~November~~opportunities, ~~2017.~~and Ascommodity ofpricing. ~~November~~Based 1,on ~~2017,~~our wecurrent ~~had~~outlook noof ~~outstanding~~commodity ~~borrowings~~prices and ~~$12.6~~our ~~million~~estimated ofproduction ~~outstanding~~for ~~letters~~2018, ofwe ~~credit~~expect ~~under~~that ~~the~~cash ~~Amended~~flows ~~Credit~~from ~~Agreement~~operating activities, ~~resulting~~cash inon ~~$137.4~~hand ~~million~~and of availability under the Amended Credit Agreement. ~~The borrowing base redetermination~~ will ~~occur~~be inadequate ~~early~~to ~~November~~meet ~~2017 and we expect~~ the ~~borrowing~~current ~~base~~2018 tooperating beand ~~set~~capital atexpenditure ~~approximately~~needs ~~$100~~of ~~million~~the ~~at such time~~Company.

As of ~~September~~March 3031, ~~2017~~2018, we ~~had~~have aposted ~~current~~an ~~income~~aggregate ~~tax~~of ~~receivable~~approximately $115 million in surety bonds in favor of ~~$27~~BOEM, third-party bonds and letters of credit, all relating to our offshore abandonment obligations.7 ~~million~~In conjunction with the acquisition of the Ram Powell field on May 1, ~~which~~2018 (see Part I, Item 1. Financial Statements – Note 16 – Subsequent Events), we ~~expect~~have toposted ~~collect~~an ~~within~~additional $200 million in surety bonds. Although the ~~next~~surety 12companies ~~months~~have not historically required collateral from us to back our surety bonds, we have provided some cash collateral on an immaterial portion of our existing surety bonds and may be required to provide additional cash collateral on existing and/or new surety bonds required by BOEM to satisfy financial assurance requirements. See Known Trends and Uncertainties above.

We have established and the Board has approved a capital expenditures budget for 2017 of $181 million. The capital expenditures budget includes approximately $22 million for exploration opportunities, $69 million for development activities and $90 million for the plugging and abandonment of idle wells and platforms. We currently expect to spend less than the approved 2017 budget. Based on our current outlook of commodity prices and our estimated production for 2017, we expect that cash flows from operating activities, cash on hand and availability under the Amended Credit Agreement will be adequate to meet the current 2017 operating and capital expenditure needs of the Company. We are currently evaluating various acquisition opportunities, which, if successful, would increase the capital requirements of the Company for 2017. We do not yet have a 2018 Board-approved capital expenditures budget, however, we expect that cash flows from operating activities, cash on hand and availability under the Amended Credit Agreement will be adequate to meet the expected 2018 operating and capital expenditure needs of the Company. Although we have no current plans to access the public or private equity or debt markets for purposes of capital for 2017 or 2018, we may consider such funding sources to provide additional capital if

Table of Contents

needed. As discussed under Strategic Review above, the Board, along with a financial advisor, continues to assess the Company’s strategic direction, including assessing its various strategic alternatives. There can be no assurance that this assessment will result in any transaction.

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. Although the surety companies have not historically required collateral from us to back our surety bonds, we have provided some cash collateral on an immaterial portion of our existing surety bonds and may be required to provide additional cash collateral on existing and/or new surety bonds required by BOEM to satisfy 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

~~Successor~~ Bank Credit Facility – On ~~the~~February ~~Effective~~28, ~~Date~~2017, ~~pursuant~~we toentered into the ~~terms~~Amended ofCredit ~~the Plan~~Agreement, ~~the~~which ~~Predecessor~~provides ~~Company’s~~for ~~Pre~~a reserve-~~Emergence~~based ~~Credit~~revolving ~~Agreement~~credit ~~was~~facility ~~amended~~ and ~~restated~~matures ason February 28, 2021. The borrowing base under the Amended Credit Agreement was redetermined to $100 million on November 8, ~~and~~2017. At May 7, 2018, the ~~obligations~~Company ~~owed~~had tono ~~the~~outstanding ~~lenders~~borrowings ~~under~~and ~~the~~$9.8 ~~Pre-Emergence~~million ~~Credit~~of ~~Agreement~~outstanding ~~were~~letters ~~converted~~of tocredit, ~~obligations~~leaving $90.2 million of availability under the Amended Credit Agreement. ~~The~~Interest on loans under the Amended Credit Agreement ~~provides~~is ~~for~~calculated ausing ~~reserve-~~the LIBOR or the base rate, at the election of the Company, plus, in each case, an applicable margin. The applicable margin is determined based ~~revolving~~on ~~credit~~borrowing ~~facility~~base utilization and ~~matures~~ranges onfrom ~~February~~2.00% ~~28,~~to ~~2021~~3.00% per annum for base rate loans and 3.00% to 4.00% per annum for LIBOR loans.

The Company’s available borrowings under the Amended Credit Agreement are set at $150 million until the first borrowing base redetermination in November 2017. At November 1, 2017, the Company had no outstanding borrowings and $12.6 million of outstanding letters of credit, leaving $137.4 million of availability under the Amended Credit Agreement. The borrowing base redetermination will occur in early November 2017 and we expect the borrowing base to be set at approximately $100 million at such time. 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 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.27

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 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 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 1.00, and (iii) a requirement to maintain minimum liquidity of at least 20% of the borrowing base. We were in compliance with all covenants under the Amended Credit Agreement as of September 30, 2017.

2022 Second Lien Notes – On the Effective Date, pursuant to the terms of the Plan, the Successor Company issued $225.0 million of the Company’s 2022 Second Lien Notes. 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. At September 30, 2017, $9.8 million had been accrued in connection with the November 30, 2017 interest payment. 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, 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.

Table of Contents

~~equal~~The toborrowing ~~the~~base ~~net~~under ~~cash~~the ~~proceeds~~Amended ofCredit ~~certain~~Agreement ~~equity~~is ~~offerings;~~redetermined ~~provided~~semi-annually, ~~that~~in atMay ~~least~~and ~~65%~~November, ofby the ~~aggregate~~lenders, ~~principal~~in ~~amount~~accordance ofwith the ~~2022~~lenders’ ~~Second~~customary ~~Lien~~practices ~~Notes~~for ~~remains~~oil ~~outstanding~~and ~~after~~gas ~~each such redemption~~loans. OnIn oraddition, ~~after~~we ~~May~~and ~~31,~~the ~~2020,~~lenders ~~the~~each ~~Company~~have ~~may~~discretion ~~redeem~~at ~~all~~any ortime, ~~part~~but ofnot ~~the~~more ~~2022~~than ~~Second~~two ~~Lien~~additional ~~Notes~~times ateach ~~redemption~~in ~~prices~~any ~~(expressed~~calendar asyear, ~~percentages~~to ofhave the ~~principal~~borrowing ~~amount)~~base ~~equal~~redetermined. toIn ~~(i)~~connection ~~105.625%~~with ~~for~~ the ~~twelve-month~~pending ~~period~~Talos ~~beginning~~combination, onthe May 311, ~~2020;~~2018 ~~(ii)~~redetermination ~~105.625%~~has ~~for~~been ~~the~~moved ~~twelve-month~~to ~~period~~June ~~beginning on May 31~~1, ~~2021; and (iii) 100~~2018.~~000%~~ ~~for~~Subject ~~the~~to ~~twelve-month~~certain ~~period beginning May 31~~exceptions, ~~2022~~the ~~and~~Amended atCredit ~~any~~Agreement ~~time~~is ~~thereafter,~~required ~~plus~~to ~~accrued~~be ~~and~~guaranteed ~~unpaid~~by ~~interest~~all atof the ~~redemption~~material ~~date.~~domestic Indirect ~~addition,~~and atindirect ~~any~~subsidiaries ~~time~~of ~~prior~~the toCompany. ~~May~~As of March 31, ~~2020~~2018, the ~~Company~~Amended ~~may~~Credit ~~redeem~~Agreement ~~all~~is orguaranteed aby ~~part~~Stone ofOffshore. ~~the~~The ~~2022~~Amended ~~Second~~Credit ~~Lien~~Agreement ~~Notes~~is atsecured aby ~~redemption~~substantially ~~price~~all ~~equal to 100%~~ of the ~~principal~~Company’s ~~amount of the 2022 Second Lien Notes to be redeemed plus a make-whole premium, plus accrued~~ and ~~unpaid~~its ~~interest~~subsidiaries’ ~~to the redemption date~~assets.

The ~~2022~~Amended ~~Second~~Credit ~~Lien~~Agreement ~~Notes~~provides ~~Indenture~~for ~~contains~~customary optional and mandatory prepayments, affirmative and negative covenants ~~that~~and ~~restrict~~events of default, including limitations on the ~~Company’s~~incurrence ~~ability~~of debt, liens, restrictive agreements, mergers, asset sales, dividends, investments, affiliate transactions and restrictions on commodity hedging. During the ~~ability~~continuance of certain events of ~~its~~default, ~~subsidiaries~~the ~~to:~~lenders ~~(i)~~may ~~incur~~take ~~additional~~a ~~debt~~number ~~and~~of ~~issue~~actions, ~~preferred~~including ~~stock;~~declaring ~~(ii)~~the ~~make~~entire ~~payments~~amount orthen ~~distributions~~outstanding onunder ~~account~~the Amended Credit Agreement due and payable (in the event of certain insolvency-related events, the ~~Company’s~~entire oramount ~~its~~then ~~restricted~~outstanding ~~subsidiaries’~~under ~~capital~~the ~~stock;~~Amended ~~(iii)~~Credit ~~sell~~Agreement ~~assets;~~will ~~(iv~~become automatically due and payable). ~~restrict~~The ~~dividends~~Amended orCredit ~~other~~Agreement ~~payments~~also requires maintenance of ~~the~~certain ~~Company’s~~financial ~~restricted~~covenants, ~~subsidiaries;~~including (vi) ~~create~~a ~~liens~~consolidated ~~that~~funded ~~secure~~ debt; ~~(vi)~~to ~~enter~~EBITDA ~~into~~ratio ~~transactions~~of ~~with~~not ~~affiliates~~more than 2.50x for the test periods ending March 31, 2018, June 30, 2018, September 30, 2018 and ~~(vii)~~December ~~merge~~31, or2018, ~~consolidate~~respectively, ~~with~~2.75x ~~another~~for ~~company~~the test period ending March 31, 2019, 3.00x ~~These~~for ~~covenants~~the ~~are~~test ~~subject~~period toending aJune ~~number~~30, of2019, ~~important~~3.50x ~~exceptions~~for the test periods ending September 30, 2019 and ~~qualifications.~~December At31, ~~any~~2019, ~~time~~respectively, ~~when~~3.00x for the ~~2022~~test ~~Second~~period ~~Lien~~ending ~~Notes~~March ~~are~~31, ~~rated~~2020, ~~investment~~2.75x ~~grade~~for bythe ~~both~~test ~~Moody’s~~periods ~~Investors~~ending ~~Service~~June 30, ~~Inc.~~2020 and ~~Standard~~September &30, ~~Poor’s~~2020, ~~Ratings~~respectively, ~~Services~~and 2.50x for the test periods ending December 31, 2020 and March 31, 2021, respectively, (ii) a ~~division~~consolidated interest coverage ratio of ~~The~~not ~~McGraw-Hill~~less ~~Companies,~~than ~~Inc~~2.75 to 1.00, and no(iii) ~~Default~~a orrequirement ~~Event~~to ofmaintain ~~Default~~minimum ~~(each~~liquidity asof ~~defined~~at inleast 20% of the ~~2022~~borrowing ~~Second~~base. ~~Lien~~We ~~Notes~~were ~~Indenture)~~in ~~has~~compliance ~~occurred~~with ~~and~~all iscovenants ~~continuing,~~under ~~many~~the ofAmended ~~these~~Credit ~~covenants~~Agreement ~~will~~as ~~terminate~~of March 31, 2018.

2022 Second Lien Notes – On March 20, 2018, in connection with the pending Talos combination, the Talos Issuers launched an offer to exchange Stone’s outstanding 2022 Second Lien Notes for newly issued 11.0% second lien notes due 2022 of the Talos Issuers. See Pending Combination with Talos above for additional information.

Cash Flow and Working Capital

Net cash provided by (used in) operating activities totaled $7032.45 million during the ~~period~~three ofmonths ~~March~~ended ~~1, 2017 through September~~March 3031, ~~2017~~2018 (Successor) ~~and~~compared (to $510.9)6 million during the period of ~~January~~March 1, 2017 through ~~February~~March 2831, 2017 (~~Predecessor~~Successor) ~~compared~~and to ($325.9) million during the ~~nine~~period ~~months~~of ~~ended~~January ~~September 30~~1, ~~2016~~2017 through February 28, 2017 (Predecessor). Operating cash flows were positively impacted during the ~~period~~three ofmonths ended March 131, ~~2017~~2018 ~~through September 30, 2017~~ (Successor) asby adecreases ~~result~~in ofTP&G aexpenses ~~federal royalty refund~~ and ~~decreases~~incentive incompensation ~~lease operating~~ expenses, ~~restructuring~~the ~~fees~~receipt of income and ~~incentive~~severance ~~compensation~~tax ~~expenses.~~refunds ~~Increases~~and an increase in the ~~prices~~average werealized price received for our oil, production. Decreases in natural gas and NGL production ~~during~~volumes, ~~2017~~and ~~were~~the ~~offset~~cash bysettlements of our derivative contracts resulted in decreases in ~~oil,~~operating ~~natural~~cash ~~gas~~flows ~~and~~for ~~NGL~~the ~~production~~three ~~volumes~~months ended March 31, 2018 (Successor). 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 expense reimbursements upon termination of the Tug Hill ~~PSA.~~purchase ~~See~~and ~~Note 7 – Divestiture for additional information on the~~ sale ~~of the Appalachia Properties~~agreement. Operating cash flows during the nine months ended September 30, 2016 (Predecessor) were impacted by approximately $15.3 million of rig subsidy and stacking charges and $27.5 million of charges related to offshore vessel and rig contract terminations. See Results of Operations below for additional information relative to commodity prices, production and operating expense variances.

Net cash ~~provided~~used byin investing activities totaled $1236.68 million during the ~~period~~three ofmonths ~~March~~ended ~~1, 2017 through September~~March 3031, ~~2017~~2018 (Successor), which primarily represents ~~$37.9~~our ~~million~~investment ofin ~~previously~~oil ~~restricted~~and ~~funds~~gas ~~for~~properties. ~~near-term~~Net ~~plugging~~cash ~~and~~provided ~~abandonment~~by ~~liabilities~~investing ~~and~~activities totaled $175.82 million ofduring ~~net proceeds from~~ the ~~sale~~period of ~~the~~March ~~Appalachia~~1, ~~Properties~~2017 ~~partially~~through ~~offset~~March by31, ~~$42.8~~2017 ~~million~~(Successor) ~~of our investment in oil~~ and ~~gas properties. Net cash provided by investing activities totaled~~ $~~421~~496.06 million during the period of January 1, 2017 through February 28, 2017 (Predecessor), which primarily represents ~~$505.4 million of~~ net proceeds from the sale of the Appalachia Properties, partially offset by ~~$75.5 million of funds restricted for near-term plugging and abandonment liabilities and~~ our investment in oil and gas properties ~~of $8~~.8 million. Net cash used in investing activities totaled $200.8 million during the nine months ended September 30, 2016 (Predecessor), which primarily represents our investment in oil and gas properties.

Net cash used in financing activities totaled $0.1 million during the three months ended March 31, 2018 (Successor), which primarily represents payments under our Building Loan. Net cash used in financing activities totaled $442.8 million during the period of January 1, 2017 through February 28, 2017 (Predecessor), which primarily represents $341.5 million in repayments of borrowings under the Pre-Emergence Credit Agreement and $100.0 million of payments to the holders of the 2017 Convertible Notes and 2022 Notes in connection with our restructuring. Net cash provided by financing activities totaled $339.6 million during the nine months ended September 30, 2016 (Predecessor), which primarily represents $477.0 million of borrowings under our Pre-Emergence Credit Agreement less $135.5 million in repayments of borrowings under our Pre-Emergence Credit Agreement.

We had working capital at ~~September~~March 3031, ~~2017~~2018 (Successor) of $~~195~~223.98 million.

Capital Expenditures

During the ~~period~~three ofmonths ~~March~~ended ~~1, 2017 through September~~March 3031, ~~2017 (Successor)~~2018, ~~additions~~net to oil and gas property costs of $48.2 million included $4.4 million of capitalized SG&A expenses, $2.7 million of capitalized interest and $11.0 million related to revisions of estimates of asset retirement obligations. During the period of January 1, 2017 through February 28, 2017 (Predecessor), additions to oil and gas ~~property~~properties ~~costs~~ of $16.23 million included $31.06 million of capitalized SG&A expenses and $21.54 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 $5720.7 million of plugging and abandonment expenditures which are recorded as a reduction of asset retirement obligations.

3928

Table of Contents

Contractual Obligations and Other Commitments

~~The~~We ~~following~~have ~~table~~various ~~summarizes our significant~~ contractual obligations and other commitments, ~~other~~in ~~than~~the ~~derivative~~normal ~~contracts~~course of operations. For further information, byplease ~~maturity~~see as“Management’s Discussion and Analysis of ~~September 30,~~Financial ~~2017~~Condition ~~(Successor)~~and (Results of Operations – Contractual Obligations and Other Commitments” in ~~thousands):~~our 2017 Annual Report on Form 10-K. There have been no material changes to this disclosure during the three months ended March 31, 2018.

	Payments Due By Period
	Total		Remaining Period in 2017		Years2018 - 2019		Years2020 - 2021		Years 2022 andBeyond
Contractual Obligations and Commitments:
7.50% Second Lien Notes due 2022	$	225,000	$	—	$	—	$	—	$	225,000
4.20% Building Loan	11,075		104		868		944		9,159
Interest and commitment fees (1)	85,505		4,515		36,063		35,391		9,536
Asset retirement obligations including accretion	618,877		70,490		81,322		36,176		430,889
Rig commitments (2)	800		800		—		—		—
Seismic data commitments	16,255		7,690		8,565		—		—
Operating lease obligations	256		96		160		—		—
Total Contractual Obligations and Commitments	$	957,768	$	83,695	$	126,978	$	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 rig services.

Table of Contents

Results of Operations

The following ~~tables~~table ~~set~~sets forth certain information with respect to our oil and gas operations for the periods presented. As a result of our application of fresh start accounting upon emergence from bankruptcy on February 28, 2017, our financial results may not be comparable to prior periods. The period of March 1, 2017 through ~~September~~March 3031, 2017 (Successor Company) and the period of January 1, 2017 through February 28, 2017 (Predecessor Company) are distinct reporting periods under fresh start accounting.

	Successor			~~Predecessor~~		Predecessor
	Three Months EndedSeptember 30, 2017			Three Months EndedSeptember 30, 2016
	Three Months EndedMarch 31, 2018		Period fromMarch 1, 2017throughMarch 31, 2017			Period fromJanuary 1, 2017throughFebruary 28, 2017
Production:
Oil (MBbls)	1,~~285~~126		410	~~1,563~~		908
Natural gas (MMcf)	2,~~220~~015		818	~~8,096~~		5,037
NGLs (MBbls)	~~114~~108		31	~~686~~		408
Oil, natural gas and NGLs (MBoe)	1,~~769~~570		577	~~3,598~~		2,156
Revenue data (in thousands): (1)
Revenue data (in thousands):
Oil revenue	$	6173,~~841~~261	$	$20,027	~~71,116~~	$	45,837
Natural gas revenue	54,~~451~~900		2,210	~~15,601~~		13,476
NGL revenue	2,473			6,666
NGLs revenue	3,188		777			8,706
Total oil, natural gas and NGL revenue	$	6981,~~765~~349	$	$23,014	~~93,383~~	$	68,019
Average prices: (2)
Average prices:
Oil (per Bbl)	$	4865.1306	$	$48.85	~~45.50~~	$	50.48
Natural gas (per Mcf)	~~2.46~~$	2.43	$	12.9370		$	2.68
NGLs (per Bbl)	~~21.69~~$	29.52	$	925.7206		$	21.34
Oil, natural gas and NGLs (per Boe)	~~39.44~~$	51.81	$	2539.9589		$	31.55
Expenses (per MBoe):
Expenses (in thousands):
Lease operating expenses	$	~~6.66~~14,380	$	$4,740	~~4.72~~	$	8,820
Transportation, processing and gathering expenses	~~0.61~~$	783	$	~~2.96~~144		$	6,933
SG&A expenses (3)	8.98			4.29
Salaries, general and administrative expenses (1)	$	12,556	$	3,322		$	9,629
DD&A expense on oil and gas properties	~~15.10~~$	20,601	$	~~16.08~~15,525		$	36,751
Expenses (per Boe):
Lease operating expenses	$	9.16	$	8.21		$	4.09
Transportation, processing and gathering expenses	$	0.50	$	0.25		$	3.22
Salaries, general and administrative expenses (1)	$	8.00	$	5.76		$	4.47
DD&A expense on oil and gas properties	$	13.12	$	26.89		$	17.05

(1) Excludes ~~Includes~~incentive ~~the~~compensation cash settlement of effective hedging contracts for the three months ended September 30, 2016. With respect to our 2017, 2018 and 2019 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)~~Net ~~Prices~~Income/Loss. ~~for~~During the three months ended ~~September~~March 31, 302018 (Successor), ~~2016~~we ~~include~~reported ~~the~~net ~~realized~~income ~~impact~~of $18.3 million ($0.91 per share). During the period of ~~derivative~~March ~~instrument~~1, ~~settlements~~2017 through March 31, ~~which~~2017 ~~increased~~(Successor), ~~the~~we ~~price~~reported a net loss of ~~oil~~$259.6 bymillion ($312.4098 per ~~Bbl~~share) and ~~increased~~during the ~~price~~period of ~~natural~~January ~~gas~~1, by2017 through February 28, 2017 (Predecessor), we reported net income of $0630.303 million ($110.99 per ~~Mcf~~share).

Write-down of 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 (3Successor), ~~Excludes~~we ~~incentive~~recognized ~~compensation~~a ~~expense~~ceiling test write-down of our U.S. oil and gas properties totaling $256.4 million. The write-down did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity. The March 31, 2017 write-down of oil and gas properties was primarily due to differences between the trailing twelve-month

4129

Table of Contents

	Successor		Predecessor
	Period fromMarch 1, 2017throughSeptember 30, 2017		Period fromJanuary 1, 2017throughFebruary 28, 2017		Nine Months EndedSeptember 30, 2016
Production:
Oil (MBbls)	2,994		908		4,746
Natural gas (MMcf)	5,593		5,037		20,042
NGLs (MBbls)	293		408		1,294
Oil, natural gas and NGLs (MBoe)	4,219		2,156		9,380
Revenue data (in thousands): (1)
Oil revenue	$	143,556	$	45,837	$	204,102
Natural gas revenue	14,201		13,476		43,327
NGLs revenue	6,264		8,706		15,119
Total oil, natural gas and NGL revenue	$	164,021	$	68,019	$	262,548
Average prices: (2)
Oil (per Bbl)	$	47.95	$	50.48	$	43.01
Natural gas (per Mcf)	2.54		2.68		2.16
NGLs (per Bbl)	21.38		21.34		11.68
Oil, natural gas and NGLs (per Boe)	38.88		31.55		27.99
Expenses (per MBoe):
Lease operating expenses	$	7.86	$	4.09	$	5.90
Transportation, processing and gathering expenses	0.72		3.22		1.99
SG&A expenses (3)	8.94		4.47		5.14
DD&A expense on oil and gas properties	17.65		17.05		17.42

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.

~~(1)~~Sale ~~Includes~~of ~~the~~Appalachia ~~cash~~Properties ~~settlement~~– ofDuring ~~effective~~the ~~hedging~~period ~~contracts~~of ~~for~~January ~~the~~1, ~~nine~~2017 ~~months~~through ~~ended~~February ~~September~~28, 302017 (Predecessor), ~~2016.~~we ~~With~~recognized ~~respect~~a to$213.5 ~~our~~million ~~2017,~~gain ~~2018~~on ~~and~~the ~~2019~~sale ~~commodity~~of ~~derivative~~the ~~contracts~~Appalachia Properties, werepresenting ~~have~~the ~~elected~~excess toof ~~not~~the ~~designate~~proceeds ~~these~~from ~~contracts~~the assale ~~cash~~over ~~flow~~the ~~hedges,~~carrying ~~and~~amount ~~accordingly,~~attributed ~~cash~~to ~~settlements~~the onoil ~~our~~and ~~derivative~~gas ~~contracts~~properties sold, adjusted for ~~periods~~transaction ~~subsequent~~costs toand ~~January~~other 1items. See Part I, ~~2017~~Item 1. ~~are~~Financial ~~reflected~~Statements in– ~~derivative~~Note ~~income~~5 ~~(expense)~~– Divestiture for additional details.

(2) Prices for the nine months ended September 30, 2016 include the realized impact of derivative instrument settlements, which increased the price of oil by $4.15 per Bbl and increased the price of natural gas by $0.48 per Mcf.

(3) Excludes incentive compensation expense.

Net Income/Loss. During the three months ended September 30, 2017 (Successor), we reported net income of $1.3 million ($0.06 per share), and during the three months ended September 30, 2016 (Predecessor), we reported a net loss of $89.6 million ($16.01 per share). During the period of March 1, 2017 through September 30, 2017 (Successor), we reported a net loss of $264.8 million ($13.24 per share), and during the period of January 1, 2017 through February 28, 2017 (Predecessor), we reported net income of $630.3 million ($110.99 per share). For the nine months ended September 30, 2016 (Predecessor), we reported a net loss of $474.2 million ($84.90 per share).

Write-down of 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), we recognized a ceiling test write-down of our U.S. oil and gas properties totaling $256.4 million. During the three months ended March 31, 2016 (Predecessor), the three months ended June 30, 2016 (Predecessor) and the three months ended September 30, 2016 (Predecessor), we recognized ceiling test write-downs of our U.S. oil and gas properties totaling $128.9 million, $118.6 million and $36.5 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 March 31, 2017 write-down of oil and gas properties 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.

Sale of Appalachia Properties – During the period of January 1, 2017 through February 28, 2017 (Predecessor), we recognized a $213.5 million gain on the sale of the Appalachia Properties, representing the excess of the proceeds from the sale over the carrying

Table of Contents

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 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.

Other expense – In connection with the termination of the Tug Hill ~~PSA~~purchase and sale agreement, we paid a break-up fee and expense reimbursements totaling $11.5 million, which is recognized as other expense during the period of January 1, 2017 through February 28, 2017 (Predecessor).

~~Other~~Production. ~~operational~~During ~~income~~the –three ~~During~~months ended March 31, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), total production volumes were 1,570 MBoe, 577 MBoe and 2,156 MBoe, respectively. Oil production during the three months ended ~~September~~March 31, 302018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, we2017 ~~recognized~~through $9February 28, 2017 (Predecessor) totaled 1,126 MBbls, 410 MBbls and 908 MBls, respectively.6 ~~million~~Natural gas production totaled 2.0 Bcf, 0.8 Bcf and 5.0 Bcf during the three months ended March 31, 2018 (Successor), the period of ~~other~~March ~~operational~~1, ~~income~~2017 ~~related~~through toMarch 31, a2017 ~~multi-year~~(Successor) ~~federal~~and ~~royalty~~the ~~refund~~period ~~claim~~of January 1, 2017 through February 28, 2017 (Predecessor), respectively. NGL production during the three months ended March 31, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), totaled approximately108 MBls, 31 MBbls and 408 MBbls, respectively.

~~Production.~~On ~~During~~February ~~the three months ended September 30~~27, 2017 ~~(Successor) and September 30~~, ~~2016~~we ~~(Predecessor),~~completed ~~total~~the ~~production~~sale ~~volumes~~of ~~were~~the ~~1,769~~Appalachia ~~MBoe~~Properties ~~and~~to ~~3,598 MBoe, respectively~~EQT. ~~Oil~~ ~~production~~For ~~during~~ the ~~three~~period ~~months~~of ~~ended~~January ~~September 30~~1, 2017 ~~(Successor)~~through ~~and~~February ~~September 30~~27, ~~2016 (Predecessor) totaled 1~~2017,~~285~~ ~~MBbls~~total ~~and 1,563 MBbls, respectively. Natural gas~~ production ~~totaled~~volumes ~~2.2~~attributable ~~Bcf~~to ~~and 8.1 Bcf during~~ the ~~three~~Appalachia ~~months~~Properties ~~ended~~were ~~September 30,~~965 ~~2017 (Successor) and September 30~~MBoe, ~~2016~~comprised ~~(Predecessor),~~of ~~respectively~~3. ~~NGL~~5 ~~production~~Bcf ~~during~~of ~~the~~natural ~~three months ended September 30~~gas, ~~2017~~57 ~~(Successor)~~MBbls ~~and~~of ~~September 30,~~oil ~~2016 (Predecessor) totaled 114 MBls~~ and ~~686~~330 MBbls, ~~respectively.~~of NGLs.

~~During~~Prices. ~~the~~Prices ~~period~~realized ofduring ~~March 1, 2017 through September 30, 2017 (Successor),~~ the ~~period~~three ~~of January 1, 2017 through February 28, 2017 (Predecessor) and the nine~~ months ended ~~September~~March 3031, ~~2016~~2018 (~~Predecessor~~Successor), ~~total~~averaged ~~production~~$65.06 ~~volumes~~per ~~were~~Bbl ~~4,219~~of ~~MBoe~~oil, $2~~,156 MBoe and 9,380 MBoe, respectively~~.43 ~~Oil~~per ~~production~~Mcf ~~during the period~~ of ~~March~~natural 1,gas ~~2017 through September 30, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor)~~ and ~~the nine months ended September 30, 2016 (Predecessor) totaled 2,994 MBbls, 908 MBls and 4,746 MBbls, respectively~~$29.52 ~~Natural~~per ~~gas~~Bbl ~~production~~of ~~totaled 5~~NGLs.6 Prices ~~Bcf,~~realized ~~5.0 Bcf and 20.0 Bcf~~ during the period of March 1, 2017 through ~~September~~March 3031, 2017 (Successor), ~~the~~averaged $48.85 ~~period~~per Bbl of ~~January 1~~oil, ~~2017~~$2.70 ~~through~~per ~~February~~Mcf ~~28,~~of ~~2017~~natural ~~(Predecessor)~~gas and ~~the~~$25.06 ~~nine~~per ~~months~~Bbl ~~ended~~of ~~September 30, 2016 (Predecessor), respectively~~NGLs. Prices ~~NGL~~realized ~~production~~ during the period of ~~March 1, 2017 through September 30, 2017 (Successor), the period of~~ January 1, 2017 through February 28, 2017 (Predecessor) ~~and~~averaged ~~the~~$50.48 ~~nine~~per ~~months~~Bbl ~~ended~~of ~~September 30~~oil, ~~2016~~$2.68 ~~(Predecessor)~~per ~~totaled~~Mcf ~~293~~of ~~MBbls,~~natural ~~408~~gas ~~MBbls~~ and ~~1,294~~$21.34 ~~MBbls,~~per ~~respectively~~Bbl of NGLs.

~~Production~~Revenue. ~~from~~Oil, ~~our~~natural ~~deep~~gas ~~water~~and ~~Amethyst~~NGL ~~well~~revenue was ~~shut-in~~$81.3 inmillion, ~~April~~$23.0 ~~2016~~million toand ~~allow~~$68.0 million for athe ~~technical~~three ~~evaluation.~~months Onended ~~November 30~~March 31, ~~2016~~2018 (Successor), wethe ~~performed~~period aof ~~routine~~March ~~shut-in~~1, of2017 ~~the~~through ~~well~~March 31, to2017 ~~record~~(Successor) ~~pressures~~ and ~~determined~~the ~~that~~period ~~pressure~~of ~~communication~~January ~~existed~~1, ~~between~~2017 ~~the~~through ~~production~~February ~~tubing~~28, ~~and~~2017 ~~production casing strings~~(Predecessor), ~~resulting~~respectively. ~~from~~The adecrease ~~suspected~~in ~~tubing~~total ~~leak.~~revenue Inin ~~late~~2018 ~~April~~was ~~2017,~~primarily wedue ~~completed~~to ~~temporary~~a ~~abandonment~~decrease ~~operations.~~in ~~The~~oil, ~~lease~~natural ~~expired~~gas and ~~was~~NGL ~~surrendered~~production ~~during~~volumes ~~the~~partially ~~second~~offset ~~quarter~~by ofan ~~2017. We~~increase ~~experienced~~in ~~production~~average ~~declines~~realized ~~during~~oil ~~the~~and ~~three~~NGL ~~months~~prices. ~~ended~~For ~~September~~the 30period of January 1, 2017 asthrough aFebruary ~~result~~27, of2017, ~~planned~~total ~~downtime~~oil, atnatural ~~the~~gas ~~Pompano~~and ~~platform~~NGL ~~for~~revenues aattributable ~~rig~~to ~~demobilization~~the ~~and~~Appalachia ~~reinstallation~~Properties ofwere ~~living~~$18.6 ~~quarters~~million.

Derivative Income/Expense. The ~~Mary~~net ~~field~~changes in ~~Appalachia~~the ~~was shut~~mark-to-market valuations and the monthly settlements of our derivative contracts are recorded in ~~from~~earnings ~~September~~in ~~2015~~derivative ~~through~~income ~~late~~(expense). ~~June~~See ~~2016~~Known Trends and Uncertainties. OnNet ~~February~~derivative 27expense for the three months ended March 31, ~~2017~~2018 (Successor) totaled $9.5 million, wecomprised ~~completed~~of ~~the~~$3.4 ~~sale~~million of expense from cash settlements and $6.1 million of non-cash expense resulting from changes in the ~~Appalachia~~fair ~~Properties~~value toof ~~EQT~~derivative instruments. ~~For~~Net derivative income for the period of ~~January~~March 1, 2017 through ~~February 27~~March 31, 2017 (Successor) totaled $2.6 million, ~~total~~comprised ~~production~~of ~~volumes~~$2.5 ~~attributable~~million toof non-cash income resulting from changes in the ~~Appalachia~~fair ~~Properties~~value ~~were~~of ~~965~~derivative ~~MBoe~~instruments, ~~comprised~~$0.2 million of 3income from cash settlements and $0.51 ~~Bcf~~million of ~~natural~~non-cash ~~gas~~expense for the amortization of the cost of the puts. Net derivative expense for the period of January 1, 572017 ~~MBbls~~through February 28, 2017 (Predecessor) totaled $1.8 million, comprised of ~~oil~~$1.7 million of non-cash expense resulting from changes in the fair value of derivative instruments and ~~330~~$0.1 ~~MBbls~~million of ~~NGLs~~non-cash expense for the amortization of the puts.

~~Prices~~Expenses. ~~Prices~~Lease ~~realized~~operating ~~during~~expenses for the three months ended ~~September~~March 3031, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) ~~averaged~~and the period of January 1, 2017 through February 28, 2017 (Predecessor) totaled $4814.134 ~~per~~million, ~~Bbl~~$4.7 ofmillion ~~oil~~and $8.8 million, respectively, or $29.4616 per ~~Mcf~~Boe, of$8.21 ~~natural~~per ~~gas~~Boe and $214.6909 per ~~Bbl~~Boe, ~~of NGLs~~respectively. ~~Prices~~ ~~realized~~Lease ~~during~~operating ~~the~~expenses ~~three~~in ~~months~~2018 ~~ended~~included ~~September 30,~~charges ~~2016~~for ~~(Predecessor)~~major ~~averaged~~maintenance ~~$45~~projects.50 ~~per~~For ~~Bbl~~the period of ~~oil,~~January $1~~.93~~, ~~per~~2017 ~~Mcf~~through ofFebruary ~~natural~~27, ~~gas~~2017, ~~and~~lease ~~$9.72~~operating ~~per~~expenses ~~Bbl~~attributable ofto ~~NGLs.~~the ~~The~~Appalachia ~~unit~~Properties ~~pricing~~totaled ~~amounts~~$2.3 ~~for~~million. For the three months ended ~~September~~March 3031, ~~2016~~2018, ~~include~~the higher per unit lease operating expense was the ~~cash~~result ~~settlement~~of the sale of ~~effective~~the ~~hedging~~lower-cost ~~contracts~~Appalachia Properties combined with lower production volumes from our GOM properties.

~~Prices~~Transportation, ~~realized~~processing ~~during~~and ~~the~~gathering ~~period~~(“TP&G”) ofexpenses ~~March~~for 1,the ~~2017~~three ~~through~~months ~~September~~ended March 3031, ~~2017~~2018 (Successor), the ~~averaged~~period ~~$47.95 per Bbl~~ of ~~oil~~March 1, ~~$2.54~~2017 ~~per~~through ~~Mcf~~March 31, of2017 ~~natural~~(Successor) ~~gas~~ and ~~$21.38 per Bbl of NGLs. Prices realized during~~ the period of January 1, 2017 through February 28, 2017 (Predecessor) totaled ~~averaged~~ $500.488 ~~per Bbl of oil~~million, $20.681 ~~per~~million ~~Mcf of natural gas~~ and $216.349 ~~per~~million, ~~Bbl of NGLs. Prices realized during the nine months ended September 30~~respectively, ~~2016~~or ~~(Predecessor) averaged~~ $430.0150 per ~~Bbl of oil~~Boe, $20.1625 per ~~Mcf~~Boe ~~of natural gas~~ and $113.6822 per ~~Bbl~~Boe, ~~of NGLs~~respectively. TP&G ~~The~~expenses ~~unit pricing amounts for the nine months ended September 30, 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. During the three months ended September~~ 30, 2016 (Predecessor), 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 nine months ended September 30, 2016 (Predecessor), our effective hedging transactions increased our average realized natural gas price by $0.48 per Mcf and increased our average realized oil price by $4.15 per Bbl. With respect to our 2017, 2018 and 2019 derivative contracts, we elected to not designate these contracts as cash flow hedges for accounting purposes, and accordingly, settlements on our derivative contracts are now recognized in earnings through derivative income (expense). See Known Trends and Uncertainties.

Revenue. Oil, natural gas and NGL revenue was $69.8 million and $93.4 million for the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor), respectively. Oil, natural gas and NGL revenue was $164.0 million, $68.0 million and $262.5 million for the period of March 1, 2017 through September 30, 2017 (Successor), the period of January 1, 2017 through

Table of Contents

~~February~~for ~~28, 2017 (Predecessor) and~~ the ~~nine months ended September 30, 2016 (~~Predecessor), ~~respectively.~~period ~~The decrease in total revenue in 2017 was~~ primarily ~~due~~related to athe ~~decrease~~Appalachia ~~in oil~~Properties, ~~natural~~which ~~gas~~were ~~and~~sold ~~NGL~~on ~~production~~February ~~volumes~~27, ~~partially offset by an increase in average realized commodity prices~~2017. For the period of January 1, 2017 through February 27, 2017, ~~total~~TP&G ~~oil,~~expenses ~~natural gas and NGL revenues~~ attributable to the Appalachia Properties ~~were~~totaled $~~18.~~6.8 million.

~~Derivative~~Production ~~Income/Expense.~~taxes ~~For~~for the three months ended ~~September 30~~March 31, ~~2016~~2018 (~~Predecessor~~Successor), ~~net~~the ~~derivative~~period ~~expense~~of ~~totaled~~March ~~$0.2~~1, ~~million~~2017 through March 31, ~~comprised~~2017 (Successor) and the period of ~~non-cash~~ ~~expense~~January ~~resulting~~1, ~~from~~2017 ~~changes~~through inFebruary ~~the~~28, ~~fair~~2017 ~~value~~(Predecessor) oftotaled ~~unsettled~~($2.2) ~~derivative~~million, ~~instruments~~$0.1 million and an$0.7 ~~immaterial~~million, ~~cash settlement~~respectively. ~~For~~During the ~~nine~~three months ended ~~September 30~~March 31, ~~2016 (Predecessor)~~2018, ~~net~~we ~~derivative~~received ~~expense~~a ~~totaled~~ $02.74 million, ~~comprised~~refund ofrelated $0to previously paid severance taxes in West Virginia.6 ~~million~~Production oftaxes ~~income~~for ~~from~~the ~~cash~~period ~~settlements~~of ~~and~~January $1.3, ~~million~~2017 ofthrough ~~non-cash~~February ~~expense~~28, ~~resulting~~2017 ~~from~~(Predecessor) ~~changes~~primarily inrelated to the ~~fair~~Appalachia ~~value~~Properties, ofwhich ~~unsettled~~were ~~derivative~~sold ~~instruments~~on February 27, 2017.

~~With~~DD&A ~~respect~~expense toon ~~our~~oil ~~2017, 2018~~ and ~~2019~~gas ~~commodity~~properties ~~derivative contracts, we elected to not designate these contracts as cash flow hedges~~ for ~~accounting purposes. Accordingly,~~ the ~~net~~three ~~changes~~months inended ~~the~~March 31, ~~mark-to-market~~2018 ~~valuations~~(Successor), ~~and~~ the ~~monthly~~period ~~settlements~~of onMarch ~~these~~1, ~~derivative~~2017 ~~contracts~~through ~~are~~March 31, ~~recorded~~2017 ~~in earnings in derivative income~~ (~~expense~~Successor). ~~Net~~and ~~derivative~~the ~~expense~~period ~~for~~of ~~the~~January ~~three~~1, ~~months~~2017 ~~ended~~through ~~September 30~~February 28, 2017 (~~Successor~~Predecessor) totaled $620.76 million, ~~comprised of~~ $115.25 million ~~of income from cash settlements~~ and $736.98 million, ofrespectively, ~~non-cash~~or ~~expense~~$13.12 ~~resulting~~per ~~from~~Boe, ~~changes~~$26.89 inper ~~the~~Boe ~~fair~~and ~~value~~$17.05 ofper ~~derivative~~Boe, ~~instruments~~respectively. ~~Net~~The ~~derivative~~decrease ~~income~~in DD&A for the ~~period~~three ofmonths ended March 131, ~~2017~~2018 ~~through~~was ~~September 30,~~primarily ~~2017~~due ~~(Successor)~~to ~~totaled~~the ~~$1.4~~ceiling ~~million,~~test ~~comprised~~write-down of ~~$2.6~~our ~~million~~oil ofand ~~income~~gas ~~from~~properties ~~cash~~at ~~settlements~~March ~~and~~31, ~~$1.2~~2017, ~~million~~which ofresulted ~~non-cash expense resulting~~ from ~~changes~~differences inbetween the ~~fair~~trailing ~~value~~twelve-month ofaverage ~~derivative~~pricing ~~instruments.~~assumption ~~Net~~used ~~derivative~~in ~~expense~~calculating ~~for~~ the ~~period~~ceiling oftest ~~January~~and 1,the ~~2017~~forward ~~through~~prices ~~February~~used ~~28,~~in ~~2017~~fresh ~~(Predecessor)~~start ~~totaled~~accounting ~~$1.8~~to ~~million,~~estimate ~~comprised~~the fair value of ~~non-cash~~our ~~expense~~oil ~~resulting~~and ~~from~~gas ~~changes~~properties inon the ~~fair~~fresh ~~value~~start reporting date of ~~derivative~~February ~~instruments~~28, 2017.

~~Expenses.~~SG&A ~~Lease~~expenses ~~operating~~(exclusive ~~expenses~~of incentive compensation) for the three months ended ~~September~~March 3031, ~~2017~~2018 (Successor) ~~and September 30~~, ~~2016 (Predecessor) totaled $11.8 million and $17.0 million, respectively. For~~ the period of March 1, 2017 ~~through~~and ~~September~~March 3031, 2017 (Successor), and the period of January 1, 2017 through February 28, 2017 (Predecessor) ~~and~~were ~~the nine months ended September 30, 2016 (Predecessor), lease operating expenses totaled~~ $3312.26 million, $83.83 million and $559.36 million, respectively~~. On a unit of production basis~~, ~~lease~~or ~~operating expenses were~~ $68.6600 per Boe, ~~and~~ $45.7276 per Boe ~~for the three months ended September 30, 2017 (Successor)~~ and ~~September 30, 2016 (Predecessor), respectively, and~~ $74.8647 per Boe, $4respectively.09 ~~per~~The ~~Boe~~decrease ~~and~~in ~~$5.90~~SG&A ~~per~~expenses ~~Boe~~that ~~for~~resulted ~~the~~from ~~period~~staff ofreductions ~~March~~made 1,in 2017 ~~through~~was ~~September 30,~~offset ~~2017~~by ~~(Successor),~~costs ~~the~~associated ~~period~~with ofthe ~~January~~pending 1,Talos ~~2017~~combination ~~through~~during ~~February 28, 2017 (Predecessor) and~~ the ~~nine~~three months ended ~~September 30~~March 31, ~~2016~~2018 (~~Predecessor~~Successor)~~, respectively~~. ~~Operating~~For ~~efficiencies,~~ the ~~implementation of cost-savings measures and the sale of the Appalachia Properties resulted in decreases in lease operating expenses in 2017. Additionally, during the~~ three months ended ~~September~~March 3031, ~~2017~~2018 (Successor), ~~lease~~SG&A ~~operating~~ expenses ~~were~~increased ~~decreased~~on ~~by $4.5 million related to~~ a ~~multi-year~~unit ~~federal~~of ~~royalty refund claim. Partially offsetting these decreases were expenses incurred during the three months ended September 30, 2017 for planned major maintenance projects. During the 2017 periods,~~ production ~~declines~~basis ~~resulted~~as ina ~~higher~~result ~~per unit lease operating expenses. For the period~~ of ~~January~~lower 1,production ~~2017~~volumes ~~through~~for ~~February~~that ~~27, 2017, lease operating expenses attributable to the Appalachia Properties totaled $2~~period.~~3 million.~~

~~Transportation,~~Interest ~~processing~~expense ~~and~~totaled ~~gathering~~$3.5 million (~~“TP&G”)~~net ~~expenses~~of ~~for~~$1.4 ~~the~~million ~~three~~of ~~months~~capitalized ~~ended September 30, 2017 (Successor~~interest) and ~~September 30, 2016 (Predecessor) totaled~~ $1.12 million ~~and~~(net ~~$10.6~~of ~~million, respectively, or~~ $0.614 ~~per~~million ~~Boe~~of ~~and~~capitalized ~~$2.96~~interest) ~~per~~for ~~Boe, respectively. For~~ the ~~period~~three ofmonths ended March 131, ~~2017~~2018 ~~through September 30, 2017~~ (Successor), and the period of ~~January~~March 1, 2017 through ~~February~~March 2831, 2017 (~~Predecessor~~Successor) ~~and the nine months ended September 30~~, ~~2016 (Predecessor), TP&G expenses totaled $3.0 million, $6.9 million and $18.7 million,~~ respectively~~, or $0~~.72 ~~per~~Interest ~~Boe,~~expense ~~$3.22 per Boe and $1.99 per Boe, respectively. TP&G expenses~~ for the ~~Predecessor periods primarily related to the Appalachia Properties which were sold on February 27,~~ 2017. ~~TP&G~~and ~~expenses~~2018 ~~for~~periods ~~the nine months ended September 30, 2016 (Predecessor)~~ included aninterest ~~approximate~~associated $4with ~~million recoupment of previously paid transportation costs allocable to~~ the ~~Federal~~2022 ~~government’s~~Second ~~portion~~Lien ofNotes ~~certain~~issued ofon ~~our deep water production. For the period of January 1, 2017 through~~ February 2728, 2017~~, TP&G expenses attributable to the Appalachia Properties totaled $6~~.~~8 million.~~

~~DD&A~~For ~~expense on oil and gas properties for~~ the ~~three~~period ~~months~~of ~~ended~~January ~~September 30~~1, 2017 ~~(Successor)~~through ~~and~~February ~~September 30~~28, ~~2016~~2017 (Predecessor) ~~totaled~~we ~~$26.7~~recorded ~~million~~an ~~and~~income tax provision of $573.86 million~~, respectively~~. ~~For~~ As ~~the~~a ~~period~~result of ~~March~~the 1,significant ~~2017~~declines ~~through~~in ~~September 30,~~commodity ~~2017~~prices ~~(Successor),~~and the ~~period~~resulting ofceiling ~~January~~test 1,write-downs ~~2017~~and ~~through~~net ~~February~~losses 28incurred, ~~2017~~we ~~(Predecessor)~~determined ~~and~~in the ~~nine~~third ~~months~~quarter ~~ended~~of ~~September 30,~~2015 ~~2016~~that ~~(Predecessor),~~it ~~DD&A~~was ~~expense~~more onlikely ~~oil~~than ~~and~~not ~~gas~~that ~~properties~~a ~~totaled~~portion ~~$74.5~~of ~~million,~~our ~~$36.8~~deferred ~~million~~tax ~~and~~assets ~~$163.4~~will ~~million,~~not ~~respectively. On~~be arealized ~~unit~~in ofthe ~~production~~future. ~~basis~~Accordingly, ~~DD&A~~we ~~expense~~established ~~was~~a ~~$15.10~~valuation ~~per~~allowance ~~Boe~~against ~~and~~a ~~$16.08~~portion ~~per~~of ~~Boe~~our ~~during~~deferred ~~the~~tax ~~three~~assets. ~~months~~We ~~ended~~also ~~September 30,~~established ~~2017~~a ~~(Successor)~~valuation ~~and~~allowance ~~September 30,~~against ~~2016~~a ~~(Predecessor),~~portion ~~respectively. For the period~~ of ~~March~~our 1,deferred ~~2017~~tax ~~through~~assets ~~September 30,~~upon ~~2017~~emergence ~~(Successor),~~from ~~the~~bankruptcy ~~period~~as part of ~~January~~fresh 1,start ~~2017 through February 28~~accounting, ~~2017 (Predecessor)~~ and the ~~nine~~subsequent ~~months~~change ~~ended~~in ~~September 30,~~the ~~2016~~valuation ~~(Predecessor),~~allowance ~~DD&A~~was ~~expense~~recorded onas aan ~~unit~~adjustment ofto ~~production~~the ~~basis~~income ~~was~~tax ~~$17~~provision.65 ~~per~~See ~~Boe~~Part I, ~~$17~~Item 1.05 ~~per~~Financial ~~Boe~~Statements ~~and~~– ~~$17.42~~Note ~~per~~10 ~~Boe,~~– ~~respectively~~Income Taxes.

Other operational expenses for the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor) totaled $0.7 million and $9.1 million, respectively. Included in other operational expenses for the three months ended September 30, 2017 (Successor) are $0.4 million of stacking charges for the platform rig at Pompano, while awaiting demobilization. Other operational expenses for the three months ended September 30, 2016 (Predecessor) included $7.5 million of charges related to the terminations of an offshore vessel contract and an Appalachian drilling rig contract and $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 period of March 1, 2017 through September 30, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the nine months

Table of Contents

ended September 30, 2016 (Predecessor), other operational expenses totaled $3.3 million, $0.5 million and $49.3 million, respectively. Other operational expenses for the period of March 1, 2017 through September 30, 2017 (Successor) included $2.1 million of stacking charges for the Pompano platform rig. Included in other operational expenses for the nine months ended September 30, 2016 (Predecessor) are the $7.5 million of 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, $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 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.

SG&A expenses (exclusive of incentive compensation) for the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor) were $15.9 million and $15.4 million, respectively. For the period of March 1, 2017 through September 30, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), SG&A expenses (exclusive of incentive compensation) were $37.7 million, $9.6 million and $48.2 million, respectively. On a unit of production basis, SG&A expenses were $8.98 per Boe and $4.29 per Boe for the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor), respectively. For the period of March 1, 2017 through September 30, 2017 (Successor), the period of January 1, 2017 through February 28, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), SG&A expenses on a unit of production basis were $8.94 per Boe, $4.47 per Boe and $5.14 per Boe, respectively. The decline in production volumes in 2017 resulted in an increase in SG&A expenses on a unit of production basis.

SG&A expenses for the period of March 1, 2017 through September 30, 2017 (Successor) included a $5.7 million charge incurred in connection with workforce reductions, consisting primarily of severance payments to affected employees and payment of related employer payroll taxes, and $3.0 million of severance costs related to the sale of the Appalachia Properties and the retirement of the prior chief executive officer of the Company. Included in SG&A expenses for the three months ended September 30, 2017 (Successor) is a $3.9 million success-based consulting fee paid in connection with a federal royalty recovery, as well as approximately $4 million of advisory fees related to the Board-requested strategic review of the Company. The charges for the workforce reductions, severance payments and consulting and advisory fees offset the overall reductions in SG&A expense that we realized in 2017 as a result of staff and other cost reductions in connection with our restructuring.

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. For the three months ended September 30, 2017 (Successor), incentive compensation expense totaled $4.6 million. This amount consisted of $4.1 million of expense related to the accrual of estimated incentive compensation bonuses pursuant to the 2017 Annual Incentive Plan, calculated based on the Company’s performance in certain 2017 fiscal year performance areas, and $0.5 million of expense related to the accrual of estimated retention awards. Incentive compensation expense for the three and nine months ended September 30, 2016 (Predecessor) totaled $2.2 million and $11.8 million, respectively, and related to the accrual of estimated incentive compensation bonuses, which were calculated based on the projected achievement of certain strategic objectives for the 2016 fiscal year pursuant to the Company’s 2005 Annual Incentive Compensation Plan.

For the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor), restructuring fees totaled $0.1 million and $5.8 million, respectively. For the period of March 1, 2017 through September 30, 2017 (Successor) and the nine months ended September 30, 2016 (Predecessor), restructuring fees totaled $0.7 million and $16.2 million, respectively. These fees related to expenses supporting our restructuring effort, including legal and financial advisory costs for Stone, our bank group and the Predecessor Company’s noteholders.

Interest expense for the three months ended September 30, 2017 (Successor) totaled $3.5 million, net of $1.2 million of capitalized interest, and included interest expense associated with the 2022 Second Lien Notes. Interest expense for the three months ended September 30, 2016 (Predecessor) totaled $16.9 million, net of $6.9 million of capitalized interest, and included interest expense associated with borrowings under our Pre-Emergence Credit Agreement and the 2017 Convertible Notes and 2022 Notes. For the period of March 1, 2017 through September 30, 2017 (Successor), interest expense totaled $8.3 million, net of $2.7 million of capitalized interest, and included interest expense associated with the 2022 Second Lien Notes. Interest expense for the nine months ended September 30, 2016 (Predecessor) totaled $49.8 million, net of $21.2 million of capitalized interest, and included interest expense associated with borrowings under our Pre-Emergence Credit Agreement and 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 full.

For the period of March 1, 2017 through September 30, 2017 (Successor), we recorded an income tax benefit of $3.6 million. For the period of January 1, 2017 through February 28, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor) we recorded an income tax provision of $3.6 million and $6.8 million, respectively. 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. We also established a valuation allowance against a portion of our deferred tax assets upon

Table of Contents

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 provision.

Off-Balance Sheet Arrangements

None.

~~Recent~~Recently Adopted Accounting ~~Developments~~Standards

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606)” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. ~~The~~We ~~standard~~adopted ~~may~~this benew ~~applied~~standard ~~retrospectively~~on orJanuary 1, 2018 using athe modified retrospective approach,. ~~with~~The ~~the~~adoption ~~cumulative effect~~ of ~~initially applying ASU 2014-09 recognized at~~ the ~~date~~standard ofdid ~~initial~~not ~~application.~~have Ina ~~August~~material ~~2015,~~effect ~~the~~on ~~FASB~~our ~~issued~~financial ~~ASU 2015-14~~position, ~~deferring~~results ~~the effective date~~ of ~~ASU~~operations ~~2014-09~~or bycash ~~one~~flows, ~~year. As~~but adid result, ~~the~~in ~~standard~~increased isdisclosures ~~effective~~related ~~for interim and annual periods beginning on or after December 15, 2017. We expect~~ to ~~apply~~revenue ~~the~~recognition ~~modified~~policies ~~retrospective~~and ~~approach~~disaggregation ~~upon adoption~~ of ~~this standard~~revenues. ~~Although~~See wePart ~~are still evaluating the effect that this new standard may have on our financial statements and related disclosures~~I, weItem 1. doFinancial ~~not~~Statements ~~anticipate~~– ~~that~~Note ~~the~~13 ~~implementation~~– ofRevenue ~~this new standard will have a material effect~~Recognition.

In ~~February~~November 2016, the FASB issued ASU 2016-0218, “~~Leases~~Statement of Cash Flows (Topic ~~842~~230)” to– ~~increase~~Restricted ~~transparency~~Cash”, which ~~and~~requires ~~comparability~~that ~~among~~amounts ~~organizations~~generally bydescribed ~~recognizing~~as ~~lease~~restricted ~~assets~~cash ~~and~~be ~~lease~~included ~~liabilities~~with oncash ~~the balance sheet~~ and ~~disclosing~~cash ~~key~~equivalents ~~information~~when ~~about~~reconciling ~~leasing~~the ~~arrangements. The standard is effective for public entities for fiscal years~~ beginning-of-period ~~after December 15, 2018,~~ and ~~for~~end-of-period ~~interim~~amounts ~~periods~~shown ~~within~~on ~~those~~the ~~fiscal~~statement ~~years,~~of ~~with~~cash ~~earlier application permitted~~flows. ~~Upon~~We ~~adoption~~adopted ~~the~~this ~~lessee will apply the~~ new standard ~~retrospectively~~on toJanuary ~~all~~1, ~~periods~~2018. ~~presented~~Retrospective orpresentation ~~retrospectively~~was ~~using~~required. aThe ~~cumulative~~adoption ~~effect~~of ~~adjustment in~~ the ~~year~~standard ofdid ~~adoption.~~not Wehave ~~are~~a ~~currently~~material ~~evaluating the~~ effect ~~that this new standard may have~~ on our financial ~~statements~~position, ~~and~~results ~~related~~of ~~disclosures~~operations or cash flows.

InRecently ~~March~~Issued ~~2016,~~Accounting 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. ASU 2016-09 became effective for us 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 extent awards are forfeited. The implementation of this new standard did not have a material effect on our financial statements or related disclosures. Standards

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 companies 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 and related disclosures.

Table of Contents

Defined Terms

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

Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. For the ~~nine~~three months ended ~~September~~March 3031, ~~2017~~2018, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $~~18.~~5.7 million impact on our ~~revenues.~~cash flows from operating activities. 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 month without the consent of the Board. Additionally, a minimum of 25% of each month’s production will not be committed to any hedge contract regardless of the price available. We believe that our outstanding hedging positions as of ~~November~~May 17, ~~2017~~2018 have hedged approximately 5446% of our estimated ~~production from estimated proved producing reserves for the remainder of 2017, 50% of our estimated~~ 2018 production from estimated proved producing reserves and 2035% of our estimated 2019 production from estimated proved producing reserves. We continue to monitor the marketplace for additional hedges we deem acceptable. See Part I, Item 1. Financial Statements – Note 97 – 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 ~~2016~~2017 Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to commodity prices.

Interest Rate Risk

We had total debt outstanding of $~~236~~235.8 million at ~~September~~March 3031, ~~2017~~2018, all of which bears interest at fixed rates. The $~~236~~235.8 million of fixed-rate debt is comprised of $225 million of the 2022 Second Lien Notes and $1110.8 million of the Building Loan.

Our ~~bank~~Amended ~~credit~~Credit ~~facility~~Agreement is subject to an adjustable interest rate. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources of this Form 10-Q. WeAt May 7, 2018, we had no outstanding borrowings under our Amended Credit Agreement ~~as of September 30, 2017~~. If we borrow funds under our ~~bank~~Amended ~~credit~~Credit ~~facility~~Agreement, we may be subject 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.

Table of Contents

ITEM 4. 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~~March 3031, ~~2017~~2018 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~~March 3031, ~~2017~~2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

4733

Table of Contents

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. OnIn ~~November~~connection ~~10,~~with 2016, a decision dismissing a Jefferson Parish Coastal Zone Management (“CZM”) test case for failure to exhaust administrative remedies was reversed. Defendants in the test case are seeking appellate review. Shortly after Stone’s ~~filed~~filing ~~a suggestion~~ of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in two of ~~its~~the three ~~CZM~~Jefferson ~~suits~~Parish ~~against~~Coastal ~~Stone~~Zone Management lawsuits without prejudice to refiling.; ~~Stone~~the ~~emerged~~claims ~~from~~of ~~bankruptcy~~the ~~effective~~Louisiana ~~February~~Attorney ~~28,~~General ~~2017,~~ and the ~~bankruptcy~~Louisiana ~~cases~~Department ~~were closed by order~~ of ~~the~~Natural ~~Bankruptcy~~Resources ~~Court~~were onnot ~~April~~similarly ~~20, 2017~~dismissed.

In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. ~~On November 12, 2015, the Plaquemines Parish Council passed a resolution instructing its attorneys to dismiss all 21 CZM suits filed by the Plaquemines Parish.~~ In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit,. In ~~and~~connection ~~the~~with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish ~~Council~~dismissed ~~rescinded~~its ~~their~~claims ~~resolution~~against toStone ~~dismiss~~without ~~all~~prejudice ~~CZM~~to ~~suits~~refiling; ~~filed~~the byclaims of the ~~Parish. Shortly~~Louisiana ~~after~~Attorney ~~Stone~~General ~~filed~~and athe ~~suggestion~~Louisiana Department of ~~bankruptcy~~Natural inResources ~~December~~were ~~2016,~~not ~~Plaquemines~~similarly ~~Parish~~ dismissed. ~~its~~The ~~CZM~~Plaquemines ~~suit~~Parish ~~against~~lawsuit ~~Stone~~has ~~without~~been ~~prejudice~~stayed topending ~~refiling.~~the ~~Stone~~conclusion ~~emerged~~of ~~from~~trials ~~bankruptcy~~in ~~effective~~five ~~February~~other 28cases, ~~2017,~~also ~~and~~filed ~~the~~in ~~bankruptcy~~Plaquemines ~~cases~~Parish ~~were~~and ~~closed~~alleging byviolations ~~order~~ of the ~~Bankruptcy~~CRMA, ~~Court~~but onnot ~~April~~involving ~~20, 2017~~Stone.

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

On each of January 4, February 2, and February 8, 2018, separate lawsuits were filed against Stone, the individual directors of the Board and other named co-defendants by stockholders of Stone. Two of the lawsuits were filed in the U.S. District Court of Delaware and the third lawsuit was filed in the U.S. District Court for the Western District Louisiana. The three lawsuits allege violations of Sections 14(a) and 20(a) of the Exchange Act and SEC Rule 14a-9 on the grounds that the Registration Statement on Form S-4 filed on December 29, 2017 (which became effective on April 9, 2018) was materially incomplete because it omitted material information concerning the transactions contemplated by the Transaction Agreement. The three lawsuits also seek certification as class actions. These lawsuits are in the preliminary stages of defense and assessment. The defendants believe that the allegations asserted in the three lawsuits are without merit and intend to vigorously defend themselves against the claims raised.

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

ITEM 1A. RISK FACTORS

~~Except~~There ~~as set forth in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, there~~ have been no material changes with respect to Stone’s risk factors previously reported in Part I, Item 1A, of our ~~2016~~2017 Annual Report on Form 10-K.

~~ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~34

Shares of our common stock 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 any authorized share repurchase program. We had no shares withheld from employees or nonemployee directors during the three months ended September 30, 2017.

Table of Contents

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Shares of our common stock are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the granting of stock awards and the lapsing of forfeiture restrictions of restricted stock. These withheld shares are not issued or considered common stock repurchases under 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 March 31, 2018.



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 May Yet be Purchased Under the Plans or Programs
January 1 - January 31, 2018	(Successor)	411	$	35.77	—
February 1 - February 28, 2018	(Successor)	—	—		—
March 1 - March 31, 2018	(Successor)	—	—		—
Total		411	35.77			$	—


(1)	Amount includes shares of our common stock withheld from employees upon the lapsing of forfeiture restrictions of restricted stock in order to satisfy the required tax withholding obligations.

ITEM 6. EXHIBITS

ExhibitNumber			Description
**2.1			Asset Purchase Agreement among Shell Offshore Inc., Exxon Mobil Corporation, Anadarko US Offshore LLC, as Sellers, and Stone Energy Offshore, L.L.C., as Purchaser, relating to the Ram Powell Unit, being Viosca Knoll Block 911, Viosca Knoll Block 912, Viosca Knoll Block 913, Viosca Knoll Block 955, Viosca Knoll Block 956, and Viosca Knoll Block 957, and related assets (Gulf of Mexico) (incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed on April 27, 2018 (File No. 001-12074))
3.1			Amended and Restated Certificate of Incorporation of Stone Energy Corporation (incorporated by reference to Exhibit 3.1 of the Registrant’s registration statement on Form 8-A filed on February 28, 2017 (File No. 001-12074))
3.2			Second Amended and Restated Bylaws of Stone Energy Corporation (incorporated by reference to Exhibit 3.2 of the Registrant’s registration statement on Form 8-A filed on February 28, 2017 (File No. 001-12074))
*†10.1			Stone Energy Corporation 2017 Annual Incentive Compensation Plan
10.1			Supplemental Indenture No. 1, dated as of April 3, 2018, by and 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 (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed on April 9, 2018 (File No. 001-12074))
*†10.2			Form of Stone Energy Corporation Retention Award Agreement
10.2			Supplemental Indenture No. 2, dated as of April 3, 2018, by and 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 (incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed on April 9, 2018 (File No. 001-12074))
*†10.3			Stone Energy Corporation Executive Severance Plan
*31.1			Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934
*31.2			Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934
*#32.1			Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350
*101.INS			XBRL Instance Document
*101.SCH			XBRL Taxonomy Extension Schema Document
*101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF			XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB			XBRL Taxonomy Extension Label Linkbase Document
*101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document

______________________________________________

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

Table of Contents



*		Filed or furnished herewith.
#		Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
**		Certain schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally a copy of such schedules and exhibits, or any section thereof, to the SEC upon request.

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~~May 17, ~~2017~~2018	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)

5037

Filing Compare · TALOS PETROLEUM LLC