Stone Energy (SGY) 10-Q 2017 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________________ 

FORM 10-Q

__________________________________________________________ 

(Mark One)

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

For the quarterly period ended September 30, 2017

or

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

For the transition period from                      to                     

Commission File Number: 1-12074

__________________________________________________________ 

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________

Delaware	72-1235413
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
625 E. Kaliste Saloom Road
Lafayette, Louisiana	70508
(Address of principal executive offices)	(Zip Code)

(337) 237-0410

(Registrant’s telephone number, including area code)

__________________________________________________________

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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

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

As of November 1, 2017, there were 19,999,112 shares of the registrant’s common stock, par value $.01 per share, outstanding.

TABLE OF CONTENTS

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheet as of September 30, 2017 and December 31, 2016	1
	Condensed Consolidated Statement of Operations for the Three Months Ended September 30, 2017 and 2016	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 Comprehensive Income (Loss) for the Three Months Ended September 30, 2017 and 2016	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
	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
	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
	Notes to Condensed Consolidated Financial Statements	8
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	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 6.	Exhibits	49
	Signatures	50

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
Assets	(Unaudited)			(Note 1)
Current assets:
Cash and cash equivalents	$	245,714		$	190,581
Restricted cash	37,684			—
Accounts receivable	35,670			48,464
Fair value of derivative contracts	2,565			—
Current income tax receivable	27,672			26,086
Other current assets	9,295			10,151
Total current assets	358,600			275,282
Oil and gas properties, full cost method of accounting:
Proved	714,515			9,616,236
Less: accumulated depreciation, depletion and amortization	(330,921		)	(9,178,442		)
Net proved oil and gas properties	383,594			437,794
Unevaluated	102,283			373,720
Other property and equipment, net	18,433			26,213
Fair value of derivative contracts	1,040			—
Other assets, net	18,252			26,474
Total assets	$	882,202		$	1,139,483
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	33,120		$	19,981
Undistributed oil and gas proceeds	5,439			15,073
Accrued interest	10,244			809
Fair value of derivative contracts	368			—
Asset retirement obligations	84,654			88,000
Current portion of long-term debt	421			408
Other current liabilities	28,503			18,602
Total current liabilities	162,749			142,873
Long-term debt	235,567			352,376
Asset retirement obligations	182,956			154,019
Fair value of derivative contracts	74			—
Other long-term liabilities	10,110			17,315
Total liabilities not subject to compromise	591,456			666,583
Liabilities subject to compromise	—			1,110,182
Total liabilities	591,456			1,776,765
Commitments and contingencies
Stockholders’ equity:
Predecessor common stock ($.01 par value; authorized 30,000,000 shares; issued 5,610,020 shares)	—			56
Predecessor treasury stock (1,658 shares, at cost)	—			(860		)
Predecessor additional paid-in capital	—			1,659,731
Successor common stock ($.01 par value; authorized 60,000,000 shares; issued 19,998,019 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.

1

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Successor			Predecessor
	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016
Operating revenue:
Oil production	$	61,841		$	71,116
Natural gas production	5,451			15,601
Natural gas liquids production	2,473			6,666
Other operational income	9,760			1,044
Total operating revenue	79,525			94,427
Operating expenses:
Lease operating expenses	11,778			16,976
Transportation, processing and gathering expenses	1,076			10,633
Production taxes	188			835
Depreciation, depletion and amortization	27,553			58,918
Write-down of oil and gas properties	—			36,484
Accretion expense	8,095			10,082
Salaries, general and administrative expenses	15,887			15,425
Incentive compensation expense	4,646			2,160
Restructuring fees	129			5,784
Other operational expenses	703			9,059
Derivative expense, net	6,685			199
Total operating expenses	76,740			166,555
Gain (loss) on Appalachia Properties divestiture	(132		)	—
Income (loss) from operations	2,653			(72,128		)
Other (income) expense:
Interest expense	3,529			16,924
Interest income	(366		)	(58		)
Other income	(276		)	(272		)
Other expense	47			16
Total other expense	2,934			16,610
Loss before income taxes	(281		)	(88,738		)
Provision (benefit) for income taxes:
Current	(1,578		)	(991		)
Deferred	—			1,888
Total income taxes	(1,578		)	897
Net income (loss)	$	1,297		$	(89,635	)
Basic income (loss) per share	$	0.06		$	(16.01	)
Diluted income (loss) per share	$	0.06		$	(16.01	)
Average shares outstanding	19,997			5,600
Average shares outstanding assuming dilution	19,997			5,600

The accompanying notes are an integral part of this statement.

2

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

	Successor			Predecessor
	Period from March 1, 2017 through September 30, 2017			Period from January 1, 2017 through February 28, 2017			Nine Months Ended September 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.

3

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Successor		Predecessor
	Three Months Ended September 30, 2017		Three Months Ended September 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.

4

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

	Successor			Predecessor
	Period from March 1, 2017 through September 30, 2017			Period from January 1, 2017 through February 28, 2017		Nine Months Ended September 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.

5

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)

	Common Stock			Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance, December 31, 2015 (Predecessor)	$	55		$	(860	)	$	1,648,687		$	(1,705,623	)	$	17,952		$	(39,789	)
Net loss	—			—			—			(590,586		)	—			(590,586		)
Adjustment for fair value accounting of derivatives, net of tax	—			—			—			—			(24,025		)	(24,025		)
Adjustment for foreign currency translation, net of tax	—			—			—			—			6,073			6,073
Exercise of stock options, vesting of restricted stock and granting of stock awards	1			—			(732		)	—			—			(731		)
Amortization of stock compensation expense	—			—			11,776			—			—			11,776
Balance, December 31, 2016 (Predecessor)	56			(860		)	1,659,731			(2,296,209		)	—			(637,282		)
Net income	—			—			—			630,317			—			630,317
Exercise of stock options, vesting of restricted stock and granting of stock awards	—			—			(172		)	—			—			(172		)
Amortization of stock compensation expense	—			—			3,527			—			—			3,527
Balance, February 28, 2017 (Predecessor)	56			(860		)	1,663,086			(1,665,892		)	—			(3,610		)
Cancellation of Predecessor equity	(56		)	860			(1,663,086		)	1,665,892			—			3,610
Balance, February 28, 2017 (Predecessor)	—			—			—			—			—			—
Issuance of Successor common stock and warrants	200			—			554,428			—			—			554,628
Balance, February 28, 2017 (Successor)	200			—			554,428			—			—			554,628
Net loss	—			—			—			(264,777		)	—			(264,777		)
Exercise of stock options, vesting of restricted stock and granting of stock awards	—			—			(19		)	—			—			(19		)
Amortization of stock compensation expense	—			—			914			—			—			914
Balance, September 30, 2017 (Successor)	$	200		$	—		$	555,323		$	(264,777	)	$	—		$	290,746

The accompanying notes are an integral part of this statement.

6

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)

	Successor			Predecessor
	Period from March 1, 2017 through September 30, 2017			Period from January 1, 2017 through February 28, 2017			Nine Months Ended September 30, 2016
Cash flows from operating activities:
Net income (loss)	$	(264,777	)	$	630,317		$	(474,180	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
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
Deferred income tax provision	—			—			10,947
(Gain) loss on sale of oil and gas properties	105			(213,453		)	—
Settlement of asset retirement obligations	(53,129		)	(3,641		)	(15,106		)
Non-cash stock compensation expense	893			2,645			6,407
Non-cash derivative expense	1,210			1,778			1,261
Non-cash interest expense	3			—			14,278
Non-cash reorganization items	—			(458,677		)	—
Other non-cash expense	877			172			6,081
Change in current income taxes	(5,156		)	3,570			21,584
Decrease in accounts receivable	6,059			6,354			3,968
(Increase) decrease in other current assets	2,382			(2,274		)	(4,426		)
Increase (decrease) in accounts payable	10,662			(4,652		)	3,217
Increase (decrease) in other current liabilities	17,944			(9,653		)	(14,222		)
Investment in derivative contracts	(2,416		)	(3,736		)	—
Other	3,054			2,490			(8,107		)
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	(42,837		)	(8,754		)	(200,622		)
Proceeds from sale of oil and gas properties, net of expenses	17,777			505,383			—
Investment in fixed and other assets	(158		)	(61		)	(1,231		)
Change in restricted funds	37,863			(75,547		)	1,046
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		)	(135,500		)
Repayments of building loan	(275		)	(24		)	(285		)
Cash payment to noteholders	—			(100,000		)	—
Debt issuance costs	—			(1,055		)	(900		)
Net payments for share-based compensation	(19		)	(173		)	(752		)
Net cash provided by (used in) financing activities	(294		)	(442,752		)	339,563
Effect of exchange rate changes on cash	—			—			(9		)
Net change in cash and cash equivalents	82,748			(27,615		)	171,640
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.

7

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 30, 2017 (Successor) and for the three month period ended September 30, 2017 (Successor), the periods from March 1, 2017 through September 30, 2017 (Successor), 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 (Predecessor) has been derived from the audited financial statements as of that date contained in our Annual Report on Form 10-K for the year ended December 31, 2016 (our “2016 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 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 from March 1, 2017 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 from Voluntary Reorganization Under Chapter 11 Proceedings

On December 14, 2016, the Company and its subsidiaries Stone Energy Offshore, L.L.C. (“Stone Offshore”) and Stone Energy Holding, L.L.C. (together with the Company, the “Debtors”)filed voluntary petitions (the “Bankruptcy Petitions”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) seeking relief under the provisions of Chapter 11 of Title 11 (“Chapter 11”) of the United States Bankruptcy Code (the “Bankruptcy Code”). On February 15, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (the “Plan”), as modified by the Confirmation Order, and on February 28, 2017, the Plan became effective (the “Effective Date”) and the Debtors emerged from bankruptcy, with the bankruptcy cases then being closed by Final Decree Closing Chapter 11 Cases and Terminating Claims Agent Services entered by the Bankruptcy Court on April 20, 2017.

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.

8

Recently Issued 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 standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 15, 2017. We expect to apply the modified retrospective approach upon adoption of this standard. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

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

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

Prior to the filing of the Bankruptcy Petitions, the Debtors and certain holders of the 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

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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 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 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 Credit Agreement was amended and restated as the Amended Credit Agreement (as defined in Note 10 – Debt). The obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement.

• All claims of creditors with unsecured claims, other than the claims by the holders of the 2022 Notes and 2017 Convertible Notes, including vendors, were unaltered and paid in full in the 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

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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%.

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
Less: Fair value of debt	(236,261		)
Less: Fair value of warrants	(15,648		)
Fair value of Successor common stock	$	538,980
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
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

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

Condensed Consolidated Balance Sheet

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

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	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
Assets
Current assets:
Cash and cash equivalents	$	198,571		$	(35,605	)	(1)	$	—			$	162,966
Restricted cash	—			75,547			(1)	—				75,547
Accounts receivable	42,808			9,301			(2)	—				52,109
Fair value of derivative contracts	1,267			—				—				1,267
Current income tax receivable	22,516			—				—				22,516
Other current assets	10,924			875			(3)	(124		)	(12)	11,675
Total current assets	276,086			50,118				(124		)		326,080
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		$	(271,082	)		$	290,718			$	1,139,011
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			(10)	—				554,428
Accumulated deficit	(2,309,788		)	2,073,984			(11)	235,804			(15)	—
Total stockholders’ equity	(649,782		)	968,606				235,804				554,628
Total liabilities and stockholders’ equity	$	1,119,375		$	(271,082	)		$	290,718			$	1,139,011

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

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

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

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

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

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

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

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

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

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

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

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

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

1 ¾% Senior Convertible Notes due 2017	$	300,000
7 ½% Senior Notes due 2022	775,000
Accrued interest	35,182
Liabilities subject to compromise of the Predecessor Company	1,110,182
Cash payment to senior noteholders	(100,000		)
Issuance of 2022 Second Lien Notes to former holders of the senior notes	(225,000		)
Fair value of equity issued to unsecured creditors	(538,980		)
Fair value of warrants issued to unsecured creditors	(15,648		)
Gain on settlement of liabilities subject to compromise	$	230,554

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

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

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

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

Fresh Start Adjustments

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

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

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

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

Reorganization Items

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

	Predecessor
	Period from January 1, 2017 through February 28, 2017
Gain on settlement of liabilities subject to compromise	$	230,554
Fresh start valuation adjustments	235,804
Reorganization professional fees and other expenses	(20,512		)
Write-off of deferred financing costs	(2,577		)
Other reorganization items	(5,525		)
Gain on reorganization items, net	$	437,744

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

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NOTE 4 – STOCKHOLDERS’ EQUITY

Common Stock

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

Warrants

As discussed in Note 2 – Reorganization, the Predecessor Company’s existing common stockholders received warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. The Company allocated $15.6 million of the enterprise value to the warrants which is reflected in “Successor additional paid-in capital” on the unaudited condensed consolidated balance sheet at September 30, 2017 (Successor).

NOTE 5 – SHARE–BASED COMPENSATION AND EMPLOYEE BENEFIT PLANS

Predecessor Awards

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

Upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for a proportionate share of the 5% of New Common Stock, plus a proportionate share of the warrants for ownership of up to 15% of the Successor Company’s common equity. Vesting continues in accordance with the applicable vesting provisions of the original awards. As of September 30, 2017, there was $14 thousand of unrecognized compensation cost related to unvested restricted shares held by the Company’s executives. The current weighted average remaining vesting period of such awards is approximately three months. All other Predecessor Company executive share-based awards were cancelled upon emergence from bankruptcy.

The board of directors of the Predecessor Company received grants of stock, totaling 10,404 shares, during the period from January 1, 2017 through February 28, 2017, representing the pro-rated portion of their annual retainer for such period. The aggregate grant date value of such stock totaled $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.

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

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the 2017 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.

Key Executive Incentive Plan

Pursuant to the terms of the Executive Claims Settlement Agreement approved by the Bankruptcy Court on January 10, 2017, the Company’s 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.

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.

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NOTE 6 – EARNINGS PER SHARE

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

The following 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 Ended September 30, 2017			Three Months Ended September 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 from March 1, 2017 through September 30, 2017			Period from January 1, 2017 through February 28, 2017			Nine Months Ended September 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	)

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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.

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

At September 30, 2016 (Predecessor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $36.5 million based on twelve-month average prices, net of applicable differentials, of $40.51 per Bbl of oil, $1.99 per Mcf of natural gas and $13.88 per Bbl of NGLs. The write-down at September 30, 2016 was decreased by $9.6 million as a result of hedges. At June 30, 2016 (Predecessor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $118.6 million based on twelve-month average prices, net of applicable differentials, of $43.49 per Bbl of oil, $1.93 per Mcf of natural gas and $9.33 per Bbl of NGLs. The write-down at June 30, 2016 was decreased by $18.1 million as a result of hedges. At March 31, 2016 (Predecessor), our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $128.9 million based on twelve-month average prices, net of applicable differentials, of $46.72 per Bbl of oil, $2.01 per Mcf of natural gas and $13.65 per Bbl of NGLs. At March 31, 2016, the write-down of oil and gas properties also included $0.3 million related to our Canadian oil and gas properties, which were deemed to be fully impaired at the end of 2015. The write-down at March 31, 2016 was decreased by $23 million as a result of hedges. The September 30, June 30 and March 31, 2016 write-downs are reflected in the statement of operations of the Predecessor Company.

NOTE 9 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

All derivatives are recognized as assets or liabilities on the balance sheet and are measured at fair value. At the end of each quarterly period, these derivatives are marked-to-market. If the derivative does not qualify or is not designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in earnings through derivative income (expense) in the statement of operations. If the derivative qualifies and is designated as a cash flow hedge, subsequent changes in the fair value of the derivative are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and natural gas production. Monthly settlements of ineffective hedges and derivatives not designated or that do not qualify for hedge accounting are recognized in earnings through derivative income (expense). The resulting cash flows from all monthly settlements are reported as cash flows from operating activities.

Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. A small portion of our cash flow hedges were 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).

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We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 2017, 2018 and 2019 oil and natural gas production from the Gulf Coast Basin. All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an “investment grade” credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we typically enter into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At November 1, 2017, our derivative instruments were with five counterparties, two of which accounted for approximately 64% of our contracted volumes. Currently, all of our outstanding derivative instruments are with lenders under our current bank credit facility. 

Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contract represents our maximum cash exposure. We are not obligated to make any further payments under the put contract regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if the New York 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 monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Settlements for our oil put contracts, oil collar contracts and fixed-price oil swaps are based on an average of the NYMEX closing price for West Texas Intermediate crude oil during the entire calendar month. Settlements for our natural gas collar contracts and fixed-price natural gas swaps are based on the NYMEX price for the last day of a respective contract month.

The following tables illustrate our derivative positions for calendar years 2017, 2018 and 2019 as of November 1, 2017:

		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

		Fixed-Price Swaps (NYMEX)
		Natural Gas			Oil
		Daily Volume (MMBtus/d)	Swap Price ($ per MMBtu)		Daily Volume (Bbls/d)	Swap Price ($ per Bbl)
2017	March - December				1,000	$	53.90
2017	July - December	11,000	$	3.00
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)
		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)
2017	March - December						1,000	$	50.00	$	56.45
2017	April - December						1,000	50.00		56.75
2018	January - December	6,000	$	2.75	$	3.24	1,000	45.00		55.35

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Derivatives not designated or not qualifying as hedging instruments

The following table discloses the location and fair value amounts of derivatives not designated or not qualifying as hedging instruments, as reported in our balance sheet, at September 30, 2017 (Successor) (in millions). We had no outstanding hedging instruments at December 31, 2016 (Predecessor). 

Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
September 30, 2017
(Successor)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	2.6	Current liabilities: Fair value of derivative contracts	$	0.4
	Long-term assets: Fair value of derivative contracts	1.0		Long-term liabilities: Fair value of derivative contracts	0.1
		$	3.6		$	0.5

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 30, 2017 (Successor), the period from January 1, 2017 through February 28, 2017 (Predecessor) and the period from March 1, 2017 through September 30, 2017 (Successor) (in millions).

Gain (Loss) Recognized in Derivative Income (Expense)
	Successor			Successor			Predecessor
	Three Months Ended September 30, 2017			Period from March 1, 2017 through September 30, 2017			Period from January 1, 2017 through February 28, 2017
Description
Commodity contracts:
Cash settlements	$	1.2		$	2.6		$	—
Change in fair value	(7.9		)	(1.2		)	(1.8		)
Total gains (losses) on derivatives not designated or not qualifying as hedging instruments	$	(6.7	)	$	1.4		$	(1.8	)

Derivatives qualifying as hedging instruments

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):

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Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Three Months Ended September 30, 2016
(Predecessor)
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives		Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)			Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2016		Location	2016		Location	2016
Commodity contracts	$	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 in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives			Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)			Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
	2016			Location	2016		Location	2016
Commodity contracts	$	(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 presents the potential impact of the offset rights associated with our recognized assets and liabilities at September 30, 2017 (Successor) (in millions):

	As Presented Without Netting			Effects of Netting			With Effects of Netting
Current assets: Fair value of derivative contracts	$	2.6		$	(0.4	)	$	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		)	0.4			—
Long-term liabilities: Fair value of derivative contracts	(0.1		)	0.1			—

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

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NOTE 10 – DEBT

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 30, 2017 (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 Effective Date, pursuant to the terms of the Plan, the Company entered into the Fifth Amended and Restated Credit Agreement with the lenders party thereto and Bank of America, N.A. (the “Amended Credit Agreement”), as administrative agent and issuing lender, which amended and replaced the Company’s Pre-Emergence Credit Agreement. The Amended Credit Agreement provides for a reserve-based revolving credit facility and matures on February 28, 2021.

The Company’s available borrowings under the Amended Credit Agreement are set at $150 million until the first borrowing base redetermination in November 2017. On September 30, 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 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.

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

24

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.

Predecessor Revolving Credit Facility

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

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

Building Loan

On November 20, 2015, we entered into an $11.8 million term loan agreement, the Building Loan, maturing on December 20, 2030. There were no changes to the terms of the Building Loan pursuant to the Plan. As of September 30, 2017, the outstanding balance under the Building Loan totaled $11.0 million.

Successor 2022 Second Lien Notes

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

Interest on the 2022 Second Lien Notes will accrue at a rate of 7.50% per annum payable semi-annually in arrears on May 31 and November 30 of each year in cash, beginning November 30, 2017. 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 (as defined below), the security interest in those assets that secure the 2022 Second Lien Notes and the related guarantee will be contractually subordinated to liens thereon that secure the Company’s Amended Credit Agreement and certain other permitted obligations as set forth in the 2022 Second Lien Notes Indenture. Consequently, the 2022 Second Lien Notes and the related guarantee will be effectively subordinated to the Amended Credit Agreement and such other permitted secured indebtedness to the extent of the value of such assets.

At any time prior to May 31, 2020, the Company may, at its option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the 2022 Second Lien Notes issued under the 2022 Second Lien Notes Indenture at a redemption price of 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.

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

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

Intercreditor Agreement

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

Predecessor Senior Notes

2017 Convertible Notes. On March 6, 2012, the Predecessor Company issued in a private offering $300 million in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes were convertible into cash, shares of our common stock 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.

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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 30, 2017 (Successor) and December 31, 2016 (Predecessor), we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. The income approach is used in this determination utilizing the third party’s proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts were the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see Note 9 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

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The following tables present our assets and liabilities that are measured at fair value on a recurring basis at September 30, 2017 (Successor) (in millions).

	Fair Value Measurements
	Successor as of
	September 30, 2017
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	9.3	$	9.3	$	—	$	—
Derivative contracts	3.6		—		0.5		3.1
Total	$	12.9	$	9.3	$	0.5	$	3.1

	Fair Value Measurements at
	Successor as of
	September 30, 2017
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	$	0.5	$	—	$	0.1	$	0.4
Total	$	0.5	$	—	$	0.1	$	0.4

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

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

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The table below presents a reconciliation for assets 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.

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NOTE 14 – ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

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

Changes in accumulated other comprehensive income (loss) by component for the three and nine months ended September 30, 2016 (Predecessor), were as follows (in millions):

	Cash Flow Hedges
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

	Cash Flow Hedges			Foreign Currency Items			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

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

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NOTE 15 – FEDERAL ROYALTY RECOVERY

In 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.

NOTE 16 – REDUCTION IN WORKFORCE

During the 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.

In addition to the workforce reduction costs, during the three months ended June 30, 2017 (Successor), we recognized a charge of $3.0 million for severance costs related to the sale of the Appalachia Properties and the retirement of the prior chief executive officer of the Company. These severance costs are reflected in SG&A expenses on the statement of operations.

NOTE 17 – OTHER OPERATIONAL EXPENSES

Other operational expenses for the period from March 1, 2017 through September 30, 2017 (Successor) totaled $3.3 million, comprised primarily of $2.1 million of stacking charges related to the platform rig at Pompano, while awaiting demobilization. Other operational 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 million loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income during the first quarter of 2016. See Note 14 – Accumulated Other Comprehensive Income (Loss). Also included in other operational expenses for the nine months ended September 30, 2016 (Predecessor) are $15.3 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, an Appalachian drilling rig and the platform rig at Pompano, a $20 million charge related to the termination of our deep water drilling rig contract with Ensco and $7.5 million of charges related to the terminations of the Appalachian drilling rig contract and a contract with an offshore vessel provider.

NOTE 18 – COMMITMENTS AND CONTINGENCIES

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management (“BOEM”) stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan.

In July 2016, BOEM issued a Notice to Lessees (“NTL”), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL also provides new procedures for how BOEM determines a lessee’s decommissioning obligations. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates.

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.

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

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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.

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

Forward-Looking Statements

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

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

• expected results from risk-weighted drilling success;

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

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

• our outlook on oil and natural gas prices;

• estimates of our oil and natural gas reserves;

• any estimates of future earnings growth;

• the impact of political and regulatory developments;

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

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

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

• the outcome of restructuring efforts and asset sales;

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

• any expected results or benefits associated with our acquisitions;

• our access to capital and our anticipated liquidity;

• estimates of future income taxes; and

• our business strategy and other plans and objectives for future operations, including the Board’s assessment of the Company’s strategic direction.

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

• 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 borrowing base under our bank credit facility and impairments;

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

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

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

• third-party interruption of sales to market;

• inflation;

• lack of availability and cost of goods and services;

• market conditions relating to potential acquisition and divestiture transactions;

• regulatory and environmental risks associated with drilling and production activities;

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

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

• competition in the oil and gas industry;

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• our inability to retain and attract key personnel;

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

• unsuccessful exploration and development drilling activities;

• hurricanes and other weather conditions;

• availability, cost and adequacy of insurance coverage;

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

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

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

Critical Accounting Policies and Estimates

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

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

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

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

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

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

Fresh Start Accounting

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

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Derivative Instruments and Hedging Activities

Through December 31, 2016, we designated our commodity derivatives as cash flow hedges for accounting purposes upon entering into the contracts. Accordingly, they were recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value were recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge was considered effective. Monthly settlements of effective hedges were reflected in revenue from oil and natural gas production. With respect to our 2017, 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 Annual Report on Form 10-K and in this Form 10-Q under Part II, Item 1A. Risk Factors, regarding our known material risk factors.

Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the 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 of the GOM deep water, 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 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. 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.

Reorganization and Emergence from Voluntary Chapter 11 Proceedings

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

In connection with our restructuring efforts, we sold our Appalachia Properties to EQT on February 27, 2017, 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. At December 31, 2016, the Appalachia Properties accounted for approximately 34% of the Predecessor Company’s total estimated proved oil and natural gas reserves on a volume equivalent basis. Upon closing of the sale on February 27, 2017, we no longer have operations or assets in Appalachia.

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 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.

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The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.

• The Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement. 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 debt instruments of the Successor Company, see Liquidity and Capital Resources below.

Management Changes

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 of Commodity Derivatives– 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, 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 an NTL, with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL also provides new procedures for how BOEM determines a lessee’s decommissioning obligations. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates.

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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.

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 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 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

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

As of November 1, 2017, we had approximately $242 million of cash on hand and $38 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the terms of the Amended Credit Agreement, and $236 million in total debt outstanding, including $225 million of 2022 Second Lien Notes and $11 million outstanding under the Building Loan. Our available borrowings under the Amended Credit Agreement are set at $150 million until the first borrowing base redetermination in November 2017. As of November 1, 2017, we had no outstanding borrowings and $12.6 million of outstanding letters of credit under the Amended Credit Agreement, resulting in $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.

As of September 30, 2017, we had a current income tax receivable of $27.7 million, which we expect to collect within the next 12 months.

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

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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 Effective Date, pursuant to the terms of the Plan, the Predecessor Company’s Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement, and the obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement. The Amended Credit Agreement provides for a reserve-based revolving credit facility and matures on February 28, 2021.

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.

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.

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.

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

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

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

Cash Flow and Working Capital

Net cash provided by (used in) operating activities totaled $70.4 million during the period of March 1, 2017 through September 30, 2017 (Successor) and ($5.9) million during the period of January 1, 2017 through February 28, 2017 (Predecessor) compared to $32.9 million during the nine months ended September 30, 2016 (Predecessor). Operating cash flows were positively impacted during the period of March 1, 2017 through September 30, 2017 (Successor) as a result of a federal royalty refund and decreases in lease operating expenses, restructuring fees and incentive compensation expenses. Increases in the prices we received for our oil, natural gas and NGL production during 2017 were offset by decreases in oil, natural gas and NGL production volumes. 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. See Note 7 – Divestiture for additional information on the sale of the Appalachia Properties. 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 by investing activities totaled $12.6 million during the period of March 1, 2017 through September 30, 2017 (Successor), which primarily represents $37.9 million of previously restricted funds for near-term plugging and abandonment liabilities and $17.8 million of net proceeds from the sale of the Appalachia Properties partially offset by $42.8 million of our investment in oil and gas properties. Net cash provided by investing activities totaled $421.0 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 $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 30, 2017 (Successor) of $195.9 million.

Capital Expenditures

During the period of March 1, 2017 through September 30, 2017 (Successor), additions 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 costs of $16.2 million included $3.0 million of capitalized SG&A expenses and $2.5 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities. These additions to oil and gas property costs exclude approximately $57 million of plugging and abandonment expenditures which are recorded as a reduction of asset retirement obligations.

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Contractual Obligations and Other Commitments

The following table summarizes our significant contractual obligations and commitments, other than derivative contracts, by maturity as of September 30, 2017 (Successor) (in thousands):

	Payments Due By Period
	Total		Remaining Period in 2017		Years 2018 - 2019		Years 2020 - 2021		Years 2022 and Beyond
Contractual Obligations and Commitments:
7.50% Second Lien Notes due 2022	$	225,000	$	—	$	—	$	—	$	225,000
4.20% Building Loan	11,075		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.

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Results of Operations

The following tables set 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 30, 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
	Three Months Ended September 30, 2017		Three Months Ended September 30, 2016
Production:
Oil (MBbls)	1,285		1,563
Natural gas (MMcf)	2,220		8,096
NGLs (MBbls)	114		686
Oil, natural gas and NGLs (MBoe)	1,769		3,598
Revenue data (in thousands): (1)
Oil revenue	$	61,841	$	71,116
Natural gas revenue	5,451		15,601
NGL revenue	2,473		6,666
Total oil, natural gas and NGL revenue	$	69,765	$	93,383
Average prices: (2)
Oil (per Bbl)	$	48.13	$	45.50
Natural gas (per Mcf)	2.46		1.93
NGLs (per Bbl)	21.69		9.72
Oil, natural gas and NGLs (per Boe)	39.44		25.95
Expenses (per MBoe):
Lease operating expenses	$	6.66	$	4.72
Transportation, processing and gathering expenses	0.61		2.96
SG&A expenses (3)	8.98		4.29
DD&A expense on oil and gas properties	15.10		16.08

(1) Includes the 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) Prices for the three months ended September 30, 2016 include the realized impact of derivative instrument settlements, which increased the price of oil by $3.40 per Bbl and increased the price of natural gas by $0.30 per Mcf.

(3) Excludes incentive compensation expense.

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	Successor		Predecessor
	Period from March 1, 2017 through September 30, 2017		Period from January 1, 2017 through February 28, 2017		Nine Months Ended September 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

(1) Includes the cash settlement of effective hedging contracts for the nine 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) 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

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

Reorganization items – During the 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, 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 operational income – During the three months ended September 30, 2017 (Successor), we recognized $9.6 million of other operational income related to a multi-year federal royalty refund claim.

Production. During the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor), total production volumes were 1,769 MBoe and 3,598 MBoe, respectively. Oil production during the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor) totaled 1,285 MBbls and 1,563 MBbls, respectively. Natural gas production totaled 2.2 Bcf and 8.1 Bcf during the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor), respectively. NGL production during the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor) totaled 114 MBls and 686 MBbls, respectively.

During 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), total production volumes were 4,219 MBoe, 2,156 MBoe and 9,380 MBoe, respectively. Oil 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 the nine months ended September 30, 2016 (Predecessor) totaled 2,994 MBbls, 908 MBls and 4,746 MBbls, respectively. Natural gas production totaled 5.6 Bcf, 5.0 Bcf and 20.0 Bcf during 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), respectively. NGL 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 the nine months ended September 30, 2016 (Predecessor) totaled 293 MBbls, 408 MBbls and 1,294 MBbls, respectively.

Production from our deep water Amethyst well was shut-in in April 2016 to allow for a technical evaluation. On November 30, 2016, we performed a routine shut-in of the well to record pressures and determined that pressure communication existed between the production tubing and production casing strings, resulting from a suspected tubing leak. In late April 2017, we completed temporary abandonment operations. The lease expired and was surrendered during the second quarter of 2017. We experienced production declines during the three months ended September 30, 2017 as a result of planned downtime at the Pompano platform for a rig demobilization and reinstallation of living quarters.

The Mary field in Appalachia was shut-in from September 2015 through late June 2016. On February 27, 2017, we completed the sale of the Appalachia Properties to EQT. For the period of January 1, 2017 through February 27, 2017, total production volumes attributable to the Appalachia Properties were 965 MBoe, comprised of 3.5 Bcf of natural gas, 57 MBbls of oil and 330 MBbls of NGLs.

Prices. Prices realized during the three months ended September 30, 2017 (Successor) averaged $48.13 per Bbl of oil, $2.46 per Mcf of natural gas and $21.69 per Bbl of NGLs. Prices realized during the three months ended September 30, 2016 (Predecessor) averaged $45.50 per Bbl of oil, $1.93 per Mcf of natural gas and $9.72 per Bbl of NGLs. The unit pricing amounts for the three months ended September 30, 2016 include the cash settlement of effective hedging contracts.

Prices realized during the period of March 1, 2017 through September 30, 2017 (Successor) averaged $47.95 per Bbl of oil, $2.54 per Mcf of natural gas and $21.38 per Bbl of NGLs. Prices realized during the period of January 1, 2017 through February 28, 2017 (Predecessor) averaged $50.48 per Bbl of oil, $2.68 per Mcf of natural gas and $21.34 per Bbl of NGLs. Prices realized during the nine months ended September 30, 2016 (Predecessor) averaged $43.01 per Bbl of oil, $2.16 per Mcf of natural gas and $11.68 per Bbl of NGLs. The 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

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February 28, 2017 (Predecessor) and the nine months ended September 30, 2016 (Predecessor), respectively. The decrease in total revenue in 2017 was primarily due to a decrease in oil, natural gas and NGL production volumes partially offset by an increase in average realized commodity prices. For the period of January 1, 2017 through February 27, 2017, total oil, natural gas and NGL revenues attributable to the Appalachia Properties were $18.6 million.

Derivative Income/Expense. For the three months ended September 30, 2016 (Predecessor), net derivative expense totaled $0.2 million, comprised of non-cash expense resulting from changes in the fair value of unsettled derivative instruments and an immaterial cash settlement. For the nine months ended September 30, 2016 (Predecessor), net derivative expense totaled $0.7 million, comprised of $0.6 million of income from cash settlements and $1.3 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.

With respect to our 2017, 2018 and 2019 commodity derivative contracts, we 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 are recorded in earnings in derivative income (expense). Net derivative expense for the three months ended September 30, 2017 (Successor) totaled $6.7 million, comprised of $1.2 million of income from cash settlements and $7.9 million of non-cash expense resulting from changes in the fair value of derivative instruments. Net derivative income for the period of March 1, 2017 through September 30, 2017 (Successor) totaled $1.4 million, comprised of $2.6 million of income from cash settlements and $1.2 million of non-cash expense resulting from changes in the fair value of derivative instruments. Net derivative expense for the period of January 1, 2017 through February 28, 2017 (Predecessor) totaled $1.8 million, comprised of non-cash expense resulting from changes in the fair value of derivative instruments.

Expenses. Lease operating expenses for the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor) totaled $11.8 million and $17.0 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), lease operating expenses totaled $33.2 million, $8.8 million and $55.3 million, respectively. On a unit of production basis, lease operating expenses were $6.66 per Boe and $4.72 per Boe for the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor), respectively, and $7.86 per Boe, $4.09 per Boe and $5.90 per Boe 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), respectively. Operating 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 30, 2017 (Successor), lease operating expenses were decreased by $4.5 million related to a multi-year federal 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 resulted in higher per unit lease operating expenses. For the period of January 1, 2017 through February 27, 2017, lease operating expenses attributable to the Appalachia Properties totaled $2.3 million.

Transportation, processing and gathering (“TP&G”) expenses for the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor) totaled $1.1 million and $10.6 million, respectively, or $0.61 per Boe and $2.96 per Boe, 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), TP&G expenses totaled $3.0 million, $6.9 million and $18.7 million, respectively, or $0.72 per Boe, $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 expenses for the nine months ended September 30, 2016 (Predecessor) included an approximate $4 million recoupment of previously paid transportation costs allocable to the Federal government’s portion of certain of our deep water production. For the period of January 1, 2017 through February 27, 2017, TP&G expenses attributable to the Appalachia Properties totaled $6.8 million.

DD&A expense on oil and gas properties for the three months ended September 30, 2017 (Successor) and September 30, 2016 (Predecessor) totaled $26.7 million and $57.8 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), DD&A expense on oil and gas properties totaled $74.5 million, $36.8 million and $163.4 million, respectively. On a unit of production basis, DD&A expense was $15.10 per Boe and $16.08 per Boe during 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), DD&A expense on a unit of production basis was $17.65 per Boe, $17.05 per Boe and $17.42 per Boe, respectively.

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

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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

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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 Accounting Developments

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 standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 15, 2017. We expect to apply the modified retrospective approach upon adoption of this standard. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

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

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.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. For the nine months ended September 30, 2017, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $18.5 million impact on our revenues. In order to manage our exposure to oil and natural gas price declines, we enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.

Our hedging policy currently provides that not more than 60% of our estimated production quantities can be hedged for any given 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 1, 2017 have hedged approximately 54% 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 20% 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 9 – 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 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 million at September 30, 2017, all of which bears interest at fixed rates. The $236 million of fixed-rate debt is comprised of $225 million of the 2022 Second Lien Notes and $11 million of the Building Loan.

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

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 30, 2017 at the reasonable assurance level.

Changes in Internal Controls Over Financial Reporting

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

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PART II – OTHER INFORMATION

ITEM 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. On November 10, 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 filed a suggestion of bankruptcy in December 2016, Jefferson Parish dismissed two of its three CZM suits against Stone without prejudice to refiling. Stone emerged from bankruptcy effective February 28, 2017, and the bankruptcy cases were closed by order of the Bankruptcy Court on April 20, 2017.

In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), 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, and the Plaquemines Parish Council rescinded their resolution to dismiss all CZM suits filed by the Parish. Shortly after Stone filed a suggestion of bankruptcy in December 2016, Plaquemines Parish dismissed its CZM suit against Stone without prejudice to refiling. Stone emerged from bankruptcy effective February 28, 2017, and the bankruptcy cases were closed by order of the Bankruptcy Court on April 20, 2017.

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

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

ITEM 1A. RISK FACTORS

Except 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 Annual Report on Form 10-K.

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 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. 

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ITEM 6. EXHIBITS

Exhibit Number	Description
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
*†10.2	Form of Stone Energy Corporation Retention Award Agreement
*†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.

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SIGNATURES

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

		STONE ENERGY CORPORATION
Date:	November 1, 2017	By:	/s/ Kenneth H. Beer
			Kenneth H. Beer
			Executive Vice President and Chief Financial Officer
			(On behalf of the Registrant and as
			Principal Financial Officer)

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