EX-99.1

EX-99.1 3 d754364dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

INDEX TO FINANCIAL STATEMENTS



Stone Energy Corporation
Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheet as December 31, 2017 (Successor) and 2016 (Predecessor)			F-3
Consolidated Statement of Operations for the Period March 1, 2017 through December 31, 2017 (Successor), the Period January 1, 2017 through February 28, 2017 (Predecessor) and the Years Ended December 31, 2016 and 2015 (Predecessor)			F-4
Consolidated Statement of Comprehensive Income (Loss) for the Period March 1, 2017 through December 31, 2017 (Successor), the Period January 1, 2017 through February 28, 2017 (Predecessor) and the Years Ended December 31, 2016 and 2015 (Predecessor)			F-5
Consolidated Statement of Changes in Stockholders’ Equity for the Period March 1, 2017 through December 31, 2017 (Successor), the Period January 1, 2017 through February 28, 2017 (Predecessor) and the Years ended December 31, 2016 and 2015 (Predecessor)			F-6
Consolidated Statement of Cash Flows for the Period March 1, 2017 through December 31, 2017 (Successor), the Period January 1, 2017 through February 28, 2017 (Predecessor) and the Years Ended December 31, 2016 and 2015 (Predecessor)			F-7
Notes to Consolidated Financial Statements			F-8
Condensed Consolidated Balance Sheet as of March 31, 2018 (Successor) and December 31, 2017 (Successor)			F-56
Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2018 (Successor), the Period March 1, 2017 through March 31, 2017 (Successor) and the Period January 1, 2017 through February 28, 2017 (Predecessor)			F-57
Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2018 (Successor), the Period March 1, 2017 through December 31, 2017 (Successor) and the Period January 1, 2017 through February 28, 2017 (Predecessor)			F-58
Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2018 (Successor), the Period March 1, 2017 through March 31, 2017 (Successor) and the Period January 1, 2017 through February 28, 2017 (Predecessor)			F-59
Notes to Condensed Consolidated Financial Statements			F-60

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Stone Energy Corporation (the Company) as of December 31, 2017 (Successor) and 2016 (Predecessor), the related consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity and cash flows for the period March 1, 2017 through December 31, 2017 (Successor), the period January 1, 2017 through February 28, 2017 (Predecessor), and the years ended December 31, 2016 and 2015 (Predecessor), and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 (Successor) and 2016 (Predecessor), and the results of its operations and its cash flows for the period March 1, 2017 through December 31, 2017 (Successor), the period January 1, 2017 through February 28, 2017 (Predecessor), and the years ended December 31, 2016 and 2015 (Predecessor), in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 9, 2018 expressed an unqualified opinion thereon.

Company Reorganization

As discussed in Note 1 to the consolidated financial statements, on February 15, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization, which became effective on February 28, 2017. Accordingly, the accompanying consolidated financial statements have been prepared in conformity with Accounting Standards Codification 852-10, Reorganizations, for the Successor as a new entity with assets, liabilities and a capital structure having carrying amounts not comparable with prior periods as described in Note 1.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2002.

New Orleans, Louisiana

March 9, 2018

F-2

STONE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands of dollars)


	Successor			Predecessor
	December 31, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	263,495		$	190,581
Restricted cash		18,742			—
Accounts receivable		39,258			48,464
Fair value of derivative contracts		879			—
Current income tax receivable		36,260			26,086
Other current assets		7,138			10,151

Total current assets		365,772			275,282
Oil and gas properties, full cost method of accounting:
Proved		713,157			9,616,236
Less: accumulated depreciation, depletion and amortization		(353,462	)		(9,178,442	)

Net proved oil and gas properties		359,695			437,794
Unevaluated		102,187			373,720
Other property and equipment, net of accumulated depreciation of $2,561 and $27,418, respectively		17,275			26,213
Other assets, net of accumulated depreciation and amortization of $5,360 at December 31, 2016		13,844			26,474

Total assets	$	858,773		$	1,139,483

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	54,226		$	19,981
Undistributed oil and gas proceeds		5,142			15,073
Accrued interest		1,685			809
Fair value of derivative contracts		8,969			—
Asset retirement obligations		79,300			88,000
Current portion of long-term debt		425			408
Other current liabilities		22,579			18,602

Total current liabilities		172,326			142,873
Long-term debt		235,502			352,376
Asset retirement obligations		133,801			154,019
Fair value of derivative contracts		3,085			—
Other long-term liabilities		5,891			17,315

Total liabilities not subject to compromise		550,605			666,583
Liabilities subject to compromise		—			1,110,182

Total liabilities		550,605			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		555,607			—
Accumulated deficit		(247,639	)		(2,296,209	)

Total stockholders’ equity		308,168			(637,282	)

Total liabilities and stockholders’ equity	$	858,773		$	1,139,483

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

F-3

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			2016			2015
Operating revenue:
Oil production	$	211,792		$	45,837		$	281,246		$	416,497
Natural gas production		18,874			13,476			64,601			83,509
Natural gas liquids production		9,610			8,706			28,888			32,322
Other operational income		10,008			903			2,657			4,369
Derivative income, net		—			—			—			7,952

Total operating revenue		250,284			68,922			377,392			544,649

Operating expenses:
Lease operating expenses		49,800			8,820			79,650			100,139
Transportation, processing and gathering expenses		4,084			6,933			27,760			58,847
Production taxes		629			682			3,148			6,877
Depreciation, depletion and amortization		99,890			37,429			220,079			281,688
Write-down of oil and gas properties		256,435			—			357,431			1,362,447
Accretion expense		21,151			5,447			40,229			25,988
Salaries, general and administrative expenses		47,817			9,629			58,928			69,384
Incentive compensation expense		8,045			2,008			13,475			2,242
Restructuring fees		739			—			29,597			—
Other operational expenses		3,359			530			55,453			2,360
Derivative expense, net		13,388			1,778			810			—

Total operating expenses		505,337			73,256			886,560			1,909,972

Gain (loss) on Appalachia Properties divestiture		(105	)		213,453			—			—

Income (loss) from operations		(255,158	)		209,119			(509,168	)		(1,365,323	)

Other (income) expense:
Interest expense		11,744			—			64,458			43,928
Interest income		(998	)		(45	)		(550	)		(580	)
Other income		(1,156	)		(315	)		(1,439	)		(1,783	)
Other expense		1,230			13,336			596			434
Reorganization items, net		—			(437,744	)		10,947			—

Total other (income) expense		10,820			(424,768	)		74,012			41,999

Income (loss) before income taxes		(265,978	)		633,887			(583,180	)		(1,407,322	)

Provision (benefit) for income taxes:
Current		(18,339	)		3,570			(5,674	)		(44,096	)
Deferred		—			—			13,080			(272,311	)

Total income taxes		(18,339	)		3,570			7,406			(316,407	)
Net income (loss)	$	(247,639	)	$	630,317		$	(590,586	)	$	(1,090,915	)

Basic income (loss) per share	$	(12.38	)	$	110.99		$	(105.63	)	$	(197.45	)
Diluted income (loss) per share	$	(12.38	)	$	110.99		$	(105.63	)	$	(197.45	)
Average shares outstanding		19,997			5,634			5,591			5,525
Average shares outstanding assuming dilution		19,997			5,634			5,591			5,525

The accompanying notes are an integral part of this statement.

F-4

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017		Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017		2016			2015
Net income (loss)	$	(247,639	)	$	630,317	$	(590,586	)	$	(1,090,915	)
Other comprehensive income (loss), net of tax effect:
Derivatives		—			—		(24,025	)		(62,758	)
Foreign currency translation		—			—		6,073			(2,605	)

Comprehensive income (loss)	$	(247,639	)	$	630,317	$	(608,538	)	$	(1,156,278	)

The accompanying notes are an integral part of this statement.

F-5

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)


	Common Stock			Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance, December 31, 2014 (Predecessor)	$	55		$	(860	)	$	1,633,801		$	(614,708	)	$	83,315		$	1,101,603
Net loss		—			—			—			(1,090,915	)		—			(1,090,915	)
Adjustment for fair value accounting of derivatives, net of tax		—			—			—			—			(62,758	)		(62,758	)
Adjustment for foreign currency translation, net of tax		—			—			—			—			(2,605	)		(2,605	)
Lapsing of forfeiture restrictions of restricted stock		—			—			(2,638	)		—			—			(2,638	)
Amortization of stock compensation expense		—			—			17,524			—			—			17,524

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
Lapsing of forfeiture restrictions 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
Lapsing of forfeiture restrictions 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			—			554,537			—			—			554,737
Balance, February 28, 2017 (Successor)		200			—			554,537			—			—			554,737
Net loss		—			—			—			(247,639	)		—			(247,639	)
Lapsing of forfeiture restrictions of restricted stock		—			—			(19	)		—			—			(19	)
Amortization of stock compensation expense		—			—			1,272			—			—			1,272
Stock issuance costs - Talos combination		—			—			(183	)					—			(183	)

Balance, December 31, 2017 (Successor)	$	200		$	—		$	555,607		$	(247,639	)	$	—		$	308,168

The accompanying notes are an integral part of this statement.

F-6

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from Jan. 1, 2017 through Feb. 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from Jan. 1, 2017 through Feb. 28, 2017			2016			2015
Cash flows from operating activities:
Net income (loss)	$	(247,639	)	$	630,317		$	(590,586	)	$	(1,090,915	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		99,890			37,429			220,079			281,688
Write-down of oil and gas properties		256,435			—			357,431			1,362,447
Accretion expense		21,151			5,447			40,229			25,988
Deferred income tax provision (benefit)		—			—			13,080			(272,311	)
(Gain) loss on sale of oil and gas properties		105			(213,453	)		—			—
Settlement of asset retirement obligations		(80,671	)		(3,641	)		(20,514	)		(72,382	)
Non-cash stock compensation expense		1,252			2,645			8,443			12,324
Excess tax benefits		—			—			—			(1,586	)
Non-cash derivative expense		15,548			1,778			1,471			16,440
Non-cash interest expense		4			—			18,404			17,788
Non-cash reorganization items		—			(458,677	)		8,332			—
Other non-cash expense		1,245			172			6,248			—
Change in current income taxes		(13,744	)		3,570			20,088			(37,377	)
(Increase) decrease in accounts receivable		2,455			6,354			(1,412	)		43,724
(Increase) decrease in other current assets		4,648			(2,274	)		(3,493	)		1,767
Decrease in inventory		—			—			—			1,304
Increase (decrease) in accounts payable		17,113			(4,652	)		1,026			(14,582	)
Increase (decrease) in other current liabilities		10,677			(9,653	)		9,897			(25,936	)
Investment in derivative contracts		(2,416	)		(3,736	)		—			—
Other		3,023			2,490			(10,135	)		(907	)

Net cash provided by (used in) operating activities		89,076			(5,884	)		78,588			247,474

Cash flows from investing activities:
Investment in oil and gas properties		(65,282	)		(8,754	)		(237,952	)		(522,047	)
Proceeds from sale of oil and gas properties, net of expenses		20,633			505,383			—			22,839
Investment in fixed and other assets		(163	)		(61	)		(1,266	)		(1,549	)
Change in restricted funds		56,805			(75,547	)		1,046			179,467

Net cash provided by (used in) investing activities		11,993			421,021			(238,172	)		(321,290	)

Cash flows from financing activities:
Proceeds from bank borrowings		—			—			477,000			5,000
Repayments of bank borrowings		—			(341,500	)		(135,500	)		(5,000	)
Proceeds from building loan		—			—			—			11,770
Repayments of building loan		(337	)		(24	)		(423	)		—
Cash payment to noteholders		—			(100,000	)		—			—
Stock issuance costs - Talos combination		(184	)		—			—			—
Debt issuance costs		—			(1,055	)		(900	)		(68	)
Excess tax benefits		—			—			—			1,586
Net payments for share-based compensation		(19	)		(173	)		(762	)		(3,127	)

Net cash provided by (used in) financing activities		(540	)		(442,752	)		339,415			10,161

Effect of exchange rate changes on cash		—			—			(9	)		(74	)

Net change in cash and cash equivalents		100,529			(27,615	)		179,822			(63,729	)
Cash and cash equivalents, beginning of period		162,966			190,581			10,759			74,488

Cash and cash equivalents, end of period	$	263,495		$	162,966		$	190,581		$	10,759

Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	$	(10,256	)		—		$	(32,130	)	$	(34,394	)
Cash refunded for income taxes, net of amounts paid		5,420			—			25,762			7,212

The accompanying notes are an integral part of this statement.

F-7

STONE ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Stone Energy Corporation (“Stone” or the “Company”) is 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 (the “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 plays 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 completed the sale of the Appalachia Properties (as defined in Note 2 – Reorganization) to EQT Corporation, through its wholly owned subsidiary EQT Production Company (“EQT”), on February 27, 2017 for net cash consideration of approximately $522.5 million. See Note 2 – Reorganization and Note 4 – Divestiture for additional information on the sale of the Appalachia Properties. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have an additional office in New Orleans, Louisiana.

Pending Combination with Talos

On November 21, 2017, Stone and certain of its subsidiaries entered into a series of related agreements pertaining to a business combination with Talos Energy LLC (“Talos Energy”) and its indirect wholly owned subsidiary Talos Production LLC (“Talos Production” and, together with Talos Energy, “Talos”). Talos Energy is controlled indirectly by entities controlled by Apollo Management VII, L.P. (“Apollo VII”), Apollo Commodities Management, L.P., with respect to Series I (together with Apollo VII, “Apollo Management”) and Riverstone Energy Partners V, L.P. (“Riverstone”).

Stone, Sailfish Energy Holdings Corporation (“New Talos”), a direct wholly owned subsidiary of Stone, and Sailfish Merger Sub Corporation, a direct wholly owned subsidiary of New Talos, entered into a Transaction Agreement (the “Transaction Agreement”) with Talos on November 21, 2017, which contemplates a series of transactions (the “Transactions”) occurring on the date of closing of the Transaction Agreement (the “Closing”) that will result in such business combination. Stone and Talos will become wholly owned subsidiaries of New Talos. At the time of the Closing, the parties intend that New Talos will become a publicly traded entity named Talos Energy, Inc. The Transactions include (i) the contribution of 100% of the equity interests in Talos Production to New Talos in exchange for shares of New Talos common stock, (ii) the contribution by entities controlled by or affiliated with Apollo Management (the “Apollo Funds”) and Riverstone (the “Riverstone Funds”) of $102 million in aggregate principal amount of 9.75% Senior Notes due 2022 issued by Talos Production and Talos Production Finance Inc. (together, the “the Talos Issuers”) to New Talos in exchange for shares of New Talos common stock, (iii) the exchange of the second lien bridge loans due 2022 issued by the Talos Issuers for newly issued 11% second lien notes issued by the Talos Issuers, and (iv) the exchange of the 7.50% Senior Second Lien Notes due 2022 (the “2022 Second Lien Notes”) issued by Stone for newly issued 11% second lien notes issued by the Talos Issuers.

Under the terms of the Transaction Agreement, each outstanding share of Stone common stock will be exchanged for one share of New Talos common stock and the current Talos stakeholders (including the Apollo Funds and the Riverstone Funds) will be issued an aggregate of approximately 34.1 million common shares of New Talos. After the completion of the Transactions contemplated by the Transaction Agreement, holders of Stone common stock immediately prior to the combination will collectively hold 37% of the outstanding New Talos common stock and Talos Energy stakeholders will hold 63% of the outstanding New Talos common stock. Outstanding warrants to acquire Stone common stock will become warrants to acquire New Talos common stock with terms and conditions substantially identical to their existing terms and conditions.

F-8

The combination was unanimously approved by the boards of directors of Stone and Talos Energy. Completion of the combination is subject to the approval of Stone shareholders, the consummation of a tender offer and consent solicitation for Stone’s 2022 Second Lien Notes, certain regulatory approvals and other customary conditions. Franklin Advisers, Inc. and MacKay Shields LLC, as investment managers for approximately 53% of the outstanding common shares of Stone as of September 30, 2017, entered into voting agreements to vote in favor of the combination, subject to certain conditions. The Transaction Agreement contains certain termination rights for Stone and Talos Energy. Stone may be required to pay a termination fee and to reimburse transaction expenses to Talos Energy if the Transaction Agreement is terminated under certain circumstances. The combination is expected to close in the second quarter of 2018. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all.

Reorganization and Emergence from Voluntary Chapter 11 Proceedings

On December 14, 2016 (the “Petition Date”), 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. See Note 2 – Reorganization for additional details.

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.

Summary of Significant Accounting Policies

A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.

Basis of Presentation:

The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Offshore, Stone Energy Holding, L.L.C. and Stone Energy Canada, ULC. On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore. On December 2, 2016, Stone Energy Canada, ULC was dissolved. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.

Reorganization and Fresh Start Accounting:

For periods subsequent to the Chapter 11 filing, but prior to emergence, ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the

F-9

ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized debt issuance costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations for the applicable periods. In addition, pre-petition obligations that were to be impacted by the Chapter 11 process were classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. See Note 2 – Reorganization and Note 3 – Fresh Start Accounting for more information regarding reorganization items and liabilities subject to compromise.

Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, 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.

The Chapter 11 proceedings did not include our former foreign subsidiary Stone Energy Canada, ULC. This subsidiary had no significant activity during 2016, except for the reclassification of approximately $6.1 million of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of Stone Energy Canada, ULC. Stone Energy Canada, ULC was dissolved on December 2, 2016.

Use of Estimates:

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (“GAAP”) 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 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.

Fair Value Measurements:

U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2017 and 2016, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.

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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.

Cash and Cash Equivalents:

We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents. On December 31, 2017, we had $18.7 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 (as defined in Note 13 – Debt).

Oil and Gas Properties:

We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.

U.S. GAAP allows the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs, the computation of DD&A expense and the assessment of impairment of oil and gas properties. Under the full cost method, all exploratory costs are capitalized, while under the successful efforts method, exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under the full cost method, DD&A expense is computed on cost centers represented by entire countries, while under the successful efforts method, cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360.

We amortize our investment in oil and gas properties through DD&A expense using the units of production (the “UOP”) method. Under the UOP method, the quarterly provision for DD&A expense is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of period reserves being determined by adding production to the end of period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs.

Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs) to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows.

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Sales of oil and gas properties are accounted for as adjustments to net oil and gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

Asset Retirement Obligations:

U.S. GAAP requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, timing of abandonment and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

Other Property and Equipment:

Our office buildings in Lafayette, Louisiana are being depreciated on the straight-line method over their estimated useful lives of 39 years.

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, the contracts 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 of these derivative contracts are recorded in earnings through derivative income (expense).

Earnings Per Common Share:

Under U.S. GAAP, certain instruments granted in share-based payment transactions are considered participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.

Production Revenue:

We recognize production revenue under the entitlements method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered or underdelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. See Recently Issued Accounting Standards below.

Income Taxes:

Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment costs relative to successful wells are

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capitalized and recovered through DD&A, although for 2015, 2016 and 2017, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code (the “IRC”) that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation. See Note 12 – Income Taxes for a discussion of the effects of the December 22, 2017 enactment of the Tax Cuts and Jobs Act.

Share-Based Compensation:

We record share-based compensation using the grant date fair value of issued stock options, stock awards, restricted stock and restricted stock units over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of stock awards, restricted stock and restricted stock units is typically determined based on the average of our high and low stock prices on the grant date.

Combination Transaction Costs:

In general, acquisition-related costs are expensed in the periods in which the costs are incurred and the services are rendered. However, some direct costs of an acquisition, such as the cost of registering and issuing equity securities to effect a business combination, are recorded as a reduction of additional paid-in-capital when incurred.

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. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers including the disaggregation of revenue and remaining performance obligations. 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, and is effective for interim and annual periods beginning on or after December 15, 2017.

We adopted this new standard on January 1, 2018 using the modified retrospective approach. The adoption of the standard did not have a material effect on our financial position, results of operations or cash flows, but will result in increased disclosures related to revenue recognition policies and disaggregation of revenues.

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

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

F-13

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, we 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 the 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 filing the Bankruptcy Petitions, on October 20, 2016, the Debtors and certain holders of the Company’s 1³⁄₄% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) and the Company’s 7¹⁄₂% 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, 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 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 net cash consideration of approximately $522.5 million. At the close of the sale of the Appalachia Properties, the Tug Hill

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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 4 – 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 New Common Stock, representing 95% of the New Common Stock and (c) $225 million of 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 13 – 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 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 such claims were undisputed.

For further information regarding the equity and debt instruments of the Predecessor Company and the Successor Company, see Note 5 – Stockholders’ Equity and Note 13 – 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 – Organization and Summary of Significant Accounting Policies, 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

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restructuring. Upon application of fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values.

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

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.

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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		371,278
Less: Fair value of debt		(236,261	)
Less: Fair value of warrants		(15,648	)

Fair value of Successor common stock	$	539,089

Shares issued upon emergence		20,000
Per share value	$	26.95

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


	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets		371,278
Plus: Asset retirement obligations (current and long-term)		290,067
Plus: Working capital and other liabilities		58,055

Reorganization value of Successor assets	$	1,139,120

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

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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):


	Predecessor Company			Reorganization Adjustments					Fresh Start Adjustments					Successor Company
Assets
Current assets:
Cash and cash equivalents	$	198,571		$	(35,605	)	(1	)	$	—				$	162,966
Restricted cash		—			75,547		(1	)		—					75,547
Accounts receivable		42,808			9,301		(2	)		—					52,109
Fair value of derivative contracts		1,267			—					—					1,267
Current income tax receivable		22,516			—					—					22,516
Other current assets		11,033			875		(3	)		(124	)	(12	)		11,784

Total current assets		276,195			50,118					(124	)				326,189
Oil and gas properties, full cost method of accounting:
Proved		9,633,907			(188,933	)	(1	)		(8,774,122	)	(12	)		670,852
Less: accumulated DD&A		(9,215,679	)		—					9,215,679		(12	)		—

Net proved oil and gas properties		418,228			(188,933	)				441,557					670,852
Unevaluated		371,140			(127,838	)	(1	)		(146,292	)	(12	)		97,010
Other property and equipment, net		25,586			(101	)	(4	)		(4,423	)	(13	)		21,062
Fair value of derivative contracts		1,819			—					—					1,819
Other assets, net		26,516			(4,328	)	(5	)		—					22,188

Total assets	$	1,119,484		$	(271,082	)			$	290,718				$	1,139,120

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	20,512		$	—				$	—				$	20,512
Undistributed oil and gas proceeds		5,917			(4,139	)	(1	)		—					1,778
Accrued interest		266			—					—					266
Asset retirement obligations		92,597			—					—					92,597
Fair value of derivative contracts		476			—					—					476
Current portion of long-term debt		411			—					—					411
Other current liabilities		17,032			(195	)	(6	)		—					16,837

Total current liabilities		137,211			(4,334	)				—					132,877
Long-term debt		352,350			(116,500	)	(7	)		—					235,850
Asset retirement obligations		151,228			(8,672	)	(1	)		54,914		(14	)		197,470
Fair value of derivative contracts		653			—					—					653
Other long-term liabilities		17,533			—					—					17,533

Total liabilities not subject to compromise		658,975			(129,506	)				54,914					584,383
Liabilities subject to compromise		1,110,182			(1,110,182	)	(8	)		—					—

Total liabilities		1,769,157			(1,239,688	)				54,914					584,383

Commitments and contingencies Stockholders’ equity:
Common stock (Predecessor)		56			(56	)	(9	)		—					—
Treasury stock (Predecessor)		(860	)		860		(9	)		—					—
Additional paid-in capital (Predecessor)		1,660,810			(1,660,810	)	(9	)		—					—
Common stock (Successor)		—			200		(10	)		—					200
Additional paid-in capital (Successor)		—			554,537		(10	)		—					554,537
Accumulated deficit		(2,309,679	)		2,073,875		(11	)		235,804		(15	)		—

Total stockholders’ equity		(649,673	)		968,606					235,804					554,737

Total liabilities and stockholders’ equity	$	1,119,484		$	(271,082	)			$	290,718				$	1,139,120

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Reorganization Adjustments

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


Sources:
Net cash proceeds from sale of Appalachia Properties(a)	$	512,472

Total sources		512,472

Uses:
Cash transferred to restricted account(b)		75,547
Break-up fee to Tug Hill		10,800
Repayment of outstanding borrowings under Pre-Emergence Credit Agreement		341,500
Repayment of 2017 Convertible Notes and 2022 Notes		100,000
Other fees and expenses(c)		20,230

Total uses		548,077

Net uses	$	(35,605	)

(a)

The closing of the sale of the Appalachia Properties occurred on February 27, 2017, but as emergence was contingent on such closing, the effects of the transaction are reflected as reorganization adjustments. See Note 4 – Divestiture for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of $522.5 million included cash consideration of $512.5 million received at closing and a $10.0 million indemnity escrow which was released subsequent to emergence from bankruptcy (see Reorganization Adjustments item number 2 below).

(b)

Reflects the movement of $75.0 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the provisions of the Amended Credit Agreement (as defined in Note 13 – Debt), and $0.5 million held in a restricted cash account for certain cure amounts in connection with the Chapter 11 proceedings.

(c)

Other fees and expenses include approximately $15.2 million of emergence and success fees, $2.7 million of professional fees and $2.4 million of payments made to seismic providers in settlement of their bankruptcy claims.

Reflects a receivable for a $10.0 million indemnity escrow with release delayed until emergence from bankruptcy, net of a $0.7 million reimbursement to Tug Hill in connection with the sale of the Appalachia Properties (see Note 4 – Divestiture).

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

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

Reflects the write-off of $2.6 million of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a $1.8 million prepayment made to Tug Hill in October 2016.

Reflects the accrual of $2.0 million in expected bonus payments under the KEIP (as defined in Note 15 – Employee Benefit Plans) and a $0.4 million termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of $2.6 million in connection with the sale of the Appalachia Properties.

Reflects the repayment of $341.5 million of outstanding borrowings under the Pre-Emergence Credit Agreement and the issuance of $225 million of 2022 Second Lien Notes as part of the settlement of the Predecessor Company 2017 Convertible Notes and 2022 Notes.

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Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):


1³⁄₄% Senior Convertible Notes due 2017	$	300,000
7¹⁄₂% Senior Notes due 2022		775,000
Accrued interest		35,182

Liabilities subject to compromise of the Predecessor Company		1,110,182
Cash payment to senior noteholders		(100,000	)
Issuance of 2022 Second Lien Notes to former holders of the senior notes		(225,000	)
Fair value of equity issued to unsecured creditors		(539,089	)
Fair value of warrants issued to unsecured creditors		(15,648	)

Gain on settlement of liabilities subject to compromise	$	230,445

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

10.

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

11.

Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):


Gain on settlement of liabilities subject to compromise	$	230,445
Professional and other fees paid at emergence		(10,648	)
Write-off of unamortized debt issuance costs		(2,577	)
Other reorganization adjustments		(1,915	)

Net impact to reorganization items		215,305
Gain on sale of Appalachia Properties		213,453
Cancellation of Predecessor Company equity		1,662,282
Other adjustments to accumulated deficit		(17,165	)

Net impact to accumulated deficit	$	2,073,875

Fresh Start Adjustments

12.

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

13.

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

14.

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

15.

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

F-20

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 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	$	230,445
Fresh start valuation adjustments		235,804
Reorganization professional fees and other expenses		(20,403	)
Write-off of unamortized debt issuance costs		(2,577	)
Other reorganization items		(5,525	)

Gain on reorganization items, net	$	437,744

The cash payments for reorganization items for the period from January 1, 2017 through February 28, 2017 include approximately $10.6 million of emergence and success fees and approximately $8.9 million of other reorganization professional fees and expenses paid on the Effective Date.

NOTE 4 — 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 the Predecessor Company’s total 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 proved reserves, we recognized a gain on the sale of $213.5 million during the period from January 1, 2017 through February 28, 2017 (Predecessor). The gain on the sale of the Appalachia Properties is computed as follows (in thousands):


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

Gain on sale	$	213,453

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.

F-21

NOTE 5 — 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 audited consolidated balance sheet at December 31, 2017 (Successor).

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 5 – Stockholders’ Equity for further details.

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


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			2016			2015
Income (numerator):
*Basic:*
Net income (loss)	$	(247,639	)	$	630,317		$	(590,586	)	$	(1,090,915	)
Net income attributable to participating securities		—			(4,995	)		—			—

Net income (loss) attributable to common stock - basic	$	(247,639	)	$	625,322		$	(590,586	)	$	(1,090,915	)

*Diluted:*
Net income (loss)	$	(247,639	)	$	630,317		$	(590,586	)	$	(1,090,915	)
Net income attributable to participating securities		—			(4,995	)		—			—

Net income (loss) attributable to common stock - diluted	$	(247,639	)	$	625,322		$	(590,586	)	$	(1,090,915	)

Weighted average shares (denominator):
Weighted average shares - basic		19,997			5,634			5,591			5,525
Dilutive effect of stock options		—			—			—			—
Dilutive effect of warrants		—			—			—			—
Dilutive effect of convertible notes		—			—			—			—

Weighted average shares - diluted		19,997			5,634			5,591			5,525

Basic income (loss) per share	$	(12.38	)	$	110.99		$	(105.63	)	$	(197.45	)

Diluted income (loss) per share	$	(12.38	)	$	110.99		$	(105.63	)	$	(197.45	)

F-22

All outstanding stock options were considered antidilutive during the period from January 1, 2017 through February 28, 2017 (Predecessor) (10,400 shares) because the exercise price of the options exceeded the average price of our common stock for the applicable period. During the years ended December 31, 2016 (Predecessor) (12,900 shares) and December 31, 2015 (Predecessor) (14,400 shares) all outstanding stock options were considered antidilutive because we had net losses for such years. On February 28, 2017, upon emergence from bankruptcy, all outstanding stock options were cancelled. See Note 16 – Share-Based Compensation.

The Predecessor Company had no outstanding restricted stock units. The board of directors of the Successor Company (the “Board”) received grants of restricted stock units on March 1, 2017. See Note 16 – Share-Based Compensation. For the period from March 1, 2017 through December 31, 2017 (Successor), all outstanding restricted stock units (62,137) 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 years ended December 31, 2016 and 2015 (Predecessor), the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such years. On February 28, 2017, upon emergence from bankruptcy, the 2017 Convertible Notes were cancelled. See Note 2 – Reorganization.

During the period from March 1, 2017 through December 31, 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 period from January 1, 2017 through February 28, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor), 47,390, 79,621 and 41,375 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock and granting of stock awards for employees and nonemployee directors.

NOTE 7 — ACCOUNTS RECEIVABLE

In our capacity as operator for our co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests. We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable are comprised of the following amounts (in thousands):


	Successor		Predecessor
	As of December 31, 2017		As of December 31, 2016
Other co-venturers	$	2,656	$	3,532
Trade		34,980		42,944
Unbilled accounts receivable		820		591
Other		802		1,397

Total accounts receivable	$	39,258	$	48,464

F-23

NOTE 8 — CONCENTRATIONS

Sales to Major Customers

Our production is sold on month-to-month contracts at prevailing prices. We obtain credit protections, such as parental guarantees, from certain of our purchasers. The following table identifies customers from whom we derived 10% or more of our total oil and natural gas revenue during the indicated periods:


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			2016			2015
Phillips 66 Company		74	%		56	%		68	%		53	%
Shell Trading (US) Company		15	%		7	%		10	%		13	%
Williams Ohio Valley Midstream LLC		—	%		12	%		2	%		9	%
Conoco		—	%		11	%		5	%		2	%

The maximum amount of credit risk exposure at December 31, 2017 (Successor) relating to these customers was $30.5 million.

We believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and natural gas production.

Production and Reserve Volumes – Unaudited

All of our estimated proved reserve volumes at December 31, 2017 (Successor) and approximately 88% of our production during 2017 were associated with our GOM deep water, conventional shelf and deep gas properties. We closed the sale of the Appalachia Properties on February 27, 2017 and no longer have assets or operations in Appalachia (see Note 4 – Divestiture).

Cash and Cash Equivalents

A substantial portion of our cash balances are not federally insured.

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 cash flow 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.

F-24

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 of these derivative contracts will be recorded in earnings through derivative income (expense).

We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 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 March 9, 2018, our derivative instruments were with four 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 2018 and 2019 as of March 9, 2018:


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

F-25


		Fixed-Price Swaps (NYMEX)
		Oil
		Daily Volume (Bbls/d)		Swap Price ($ per Bbl)
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
2019	January - December		2,000		56.13


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

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 December 31, 2017 (Successor) (in thousands). We had no outstanding hedging instruments at December 31, 2016 (Predecessor).

Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at

December 31, 2017

(Successor)


	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	879	Current liabilities: Fair value of derivative contracts	$	8,969
	Long-term assets: Fair value of derivative contracts		—	Long-term liabilities: Fair value of derivative contracts		3,085

		$	879		$	12,054

F-26

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 indicated periods (in thousands):

Gain (Loss) Recognized in Derivative Income (Expense)


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended
Description	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			December 31, 2016		December 31, 2015
Commodity contracts:
Cash settlements	$	2,161		$	—		$	—	$	17,385
Change in fair value		(15,549	)		(1,778	)		—		(12,146	)

Total gains (losses) on derivatives not designated or not qualifying as hedging instruments	$	(13,388	)	$	(1,778	)	$	—	$	5,239

Derivatives qualifying as hedging instruments

None of our derivative contracts outstanding as of December 31, 2017 (Successor) were designated as accounting hedges. We had no outstanding derivatives at December 31, 2016 (Predecessor). During 2016 and 2015, we had outstanding derivatives that were designated and qualified as hedging instruments. The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the years ended December 31, 2016 and 2015 (Predecessor) (in thousands):

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations

for the Years Ended December 31, 2016 and 2015

(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)
				Location			Location
	2016				2016			2016
Commodity contracts	$	(1,648	)	Operating revenue - oil/natural gas production	$	35,457	Derivative income (expense), net	$	(810	)

Total	$	(1,648	)		$	35,457		$	(810	)


	2015				2015			2015
Commodity contracts	$	52,630		Operating revenue - oil/natural gas production	$	149,955	Derivative income (expense), net	$	2,713

Total	$	52,630			$	149,955		$	2,713

(a)	For the year ended December 31, 2016, effective hedging contracts increased oil revenue by $23,747 and increased natural gas revenue by $11,710. For the year ended December 31, 2015, effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338.

F-27

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 December 31, 2017 (Successor) (in thousands):


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

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

NOTE 10 — FAIR VALUE MEASUREMENTS

U.S. GAAP establishes 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 December 31, 2017 (Successor) and 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 are 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.

F-28

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 (Successor) (in thousands):


	Fair Value Measurements Successor as of December 31, 2017
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	5,081	$	5,081	$	—	$	—
Derivative contracts		879		—		—		879

Total	$	5,960	$	5,081	$	—	$	879


	Fair Value Measurements Successor as of December 31, 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	$	12,054	$	—	$	10,110	$	1,944

Total	$	12,054	$	—	$	10,110	$	1,944

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


	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)	$	8,746	$	8,746	$	—	$	—

Total	$	8,746	$	8,746	$	—	$	—

F-29

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 December 31, 2017 (Successor) and the period from January 1, 2017 through February 28, 2017 (Predecessor) (in thousands):


	Hedging Contracts, net
	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017
Beginning balance	$	3,087		$	—
Total gains/(losses) (realized or unrealized):
Included in earnings		(5,201	)		(649	)
Included in other comprehensive income		—			—
Purchases, sales, issuances and settlements		1,049			3,736
Transfers in and out of Level 3		—			—

Ending balance	$	(1,065	)	$	3,087

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 December 31, 2017	$	(4,699	)

The fair value of cash and cash equivalents approximated book value at December 31, 2017 and 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 December 31, 2017, the fair value of the 2022 Second Lien Notes was approximately $227.3 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 at 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.

F-30

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 following table presents the change in our asset retirement obligations during the indicated periods (in thousands, inclusive of current portion):


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			2016			2015
Beginning balance	$	290,067		$	242,019		$	225,866		$	316,409
Liabilities incurred		2,280			—			2,338			15,933
Liabilities settled		(81,197	)		(3,641	)		(19,630	)		(72,713	)
Divestment of properties		—			(8,672	)		—			(248	)
Accretion expense		21,151			5,447			40,229			25,988
Revision of estimates		(19,200	)		—			(6,784	)		(59,503	)
Fair value fresh start adjustment		—			54,914			—			—

Asset retirement obligations, end of period	$	213,101		$	290,067		$	242,019		$	225,866

NOTE 12 — INCOME TAXES

An analysis of our deferred taxes follows (in thousands):


	Successor			Predecessor
	As of December 31, 2017			As of December 31, 2016
Tax effect of temporary differences:
Net operating loss carryforwards	$	66,304		$	201,557
Oil and gas properties		12,035			85,772
Asset retirement obligations		44,751			85,312
Stock compensation		278			3,294
Derivatives		3,110			—
Accrued incentive compensation		2,269			954
Debt issuance costs		644			7,480
Other		1,600			441

Total deferred tax assets (liabilities)		130,991			384,810
Valuation allowance		(130,991	)		(384,810	)

Net deferred tax assets (liabilities)	$	—		$	—

Upon our emergence from bankruptcy, pursuant to the terms of the Plan, a substantial portion of the Company’s pre-petition debt was extinguished (see Note 2 – Reorganization). For tax purposes, absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. After consideration of the market value of the Company’s equity

F-31

upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of U.S. CODI is approximately $257 million, which will reduce the value of the Company’s U.S. net operating losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2018. The estimated results of the attribute reduction have been reflected in the Company’s ending balance of deferred tax assets for the year ended December 31, 2017 (Successor). The Successor Company also has various state net operating loss carryforwards that are subject to reduction as a result of the CODI being excluded from taxable income, however, subsequent to the sale of the Appalachia Properties, our state income tax exposure is not expected to be material.

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

We estimate that we had ($18.3) million and $3.6 million, respectively, of current federal income tax expense (benefit) for the periods of March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor). For the years ended December 31, 2016 and 2015 (Predecessor) we had ($5.7) million and ($44.1) million, respectively, of current federal income tax (benefits). There was no deferred income tax expense (benefit) recorded for the periods of March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor). For the years ended December 31, 2016 and 2015 (Predecessor), we recorded a deferred income tax expense (benefit) of $13.1 million and ($272.3) million, respectively. The deferred income tax benefit in 2015 was a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (see Note 22 – Supplemental Information on Oil and Natural Gas Operations – Unaudited). We had current income tax receivables of $36.3 million and $26.1 million at December 31, 2017 (Successor) and 2016 (Predecessor), respectively, both of which related to expected tax refunds from the carryback of net operating losses to previous tax years. We received $20.6 million of the tax refund subsequent to December 31, 2017.

For tax reporting purposes, our net operating loss carryforwards totaled approximately $315.7 million at December 31, 2017 (net of the aforementioned CODI reduction). If not utilized, such carryforwards would begin to expire in 2035 and would fully expire in 2036. Additionally, IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of IRC Section 382. Accordingly, we estimate that approximately $127 million of our net operating loss carryforwards will be subject to the annual IRC Section 382 limitation, with the remaining $189 million of net operating loss carryforwards being unlimited.

In addition, we had approximately $1.2 million in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these and other carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized. 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

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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 December 31, 2017 (Successor), our valuation allowance totaled $131.0 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.

The following table provides a reconciliation of the statutory federal income tax rate to the Company’s effective income tax rate as a percentage of income before income taxes for the indicated periods:


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			2016			2015
Income tax expense computed at the statutory federal income tax rate		35.0	%		35.0	%		35.0	%		35.0	%
Tax Act rate change		(32.8	)		—			—			—
State taxes		(0.7	)		0.3			0.2			0.6
Change in valuation allowance		5.3			(37.8	)		(35.0	)		(12.8	)
IRC Sec. 162(m) limitation		0.4			—			(0.3	)		(0.1	)
Tax deficits on stock compensation		(0.6	)		0.6			(0.7	)		(0.1	)
Reorganization fees		0.3			2.5			(0.3	)		—
Other		—			—			(0.2	)		(0.1	)

Effective income tax rate		6.9	%		0.6	%		(1.3	)%		22.5	%

There were no income taxes allocated to accumulated other comprehensive income for the periods of March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor). Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to ($13.1) million, ($35.7) million for the years ended December 31, 2016 and 2015 (Predecessor), respectively.

As of December 31, 2017 (Successor), we had unrecognized tax benefits of $491 thousand. If recognized, all of our unrecognized tax benefits would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows (in thousands):


	Successor		Predecessor
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017
Total unrecognized tax benefits, beginning balance	$	491	$	491
Increases (decreases) in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		—		—
Tax positions taken during the current period		—		—
Settlements with taxing authorities		—		—
Lapse of applicable statute of limitations		—		—

Total unrecognized tax benefits, ending balance	$	491	$	491

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Our unrecognized tax benefits pertain to a proposed state income tax audit adjustment. We believe that our unrecognized tax benefits may be reduced to zero within the next 12 months upon completion and ultimate settlement of the examination.

It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. We recognized $33 thousand and $7 thousand, respectively, of interest expense and no penalties related to uncertain tax positions for the periods of March 1, 2017 through December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor). We recognized $46 thousand of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2016 (Predecessor). We recognized $131 thousand of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2015 (Predecessor). The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet.

The tax years 2014 through 2017 remain subject to examination by major tax jurisdictions.

NOTE 13 — DEBT

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


	Successor			Predecessor
	December 31, 2017			December 31, 2016
7¹⁄₂% Senior Second Lien Notes due 2022	$	225,000		$	—
1³⁄₄% Senior Convertible Notes due 2017		—			300,000
7¹⁄₂% Senior Notes due 2022		—			775,000
Predecessor revolving credit facility		—			341,500
4.20% Building Loan		10,927			11,284

Total debt	$	235,927		$	1,427,784
Less: current portion of long-term debt		(425	)		(408	)
Less: liabilities subject to compromise		—			(1,075,000	)

Long-term debt	$	235,502		$	352,376

Reorganization

On December 14, 2016, the Debtors filed Bankruptcy Petitions seeking relief under 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 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 December 31, 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”).

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Reclassification of Debt

The face values of the 2017 Convertible Notes of $300 million and the 2022 Notes of $775 million were reclassified as liabilities subject to compromise in the accompanying consolidated balance sheet at December 31, 2016 (Predecessor). See Note 1 – Organization and Summary of Significant Accounting Policies.

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. (as amended from time to time, the “Amended Credit Agreement”), as administrative agent and issuing lender, which amended and replaced the Company’s Pre-Emergence Credit Agreement. The Amended Credit Agreement provides for a reserve-based revolving credit facility and matures on February 28, 2021.

The Company’s available borrowings under the Amended Credit Agreement were initially set at $150 million until the first borrowing base redetermination in November 2017. On November 8, 2017, the borrowing base under the Amended Credit Agreement was redetermined to $100 million. On December 31, 2017, the Company had no outstanding borrowings and $12.6 million of outstanding letters of credit, leaving $87.4 million of availability under the Amended Credit Agreement. 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 each 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 December 31, 2017, the Amended Credit Agreement is guaranteed by Stone Offshore. The Amended Credit Agreement is secured by substantially all of the Company’s and its subsidiaries’ assets.

The Amended Credit Agreement provides for customary optional and mandatory prepayments, affirmative and negative covenants and events of default, including limitations on the incurrence of debt, liens, restrictive agreements, mergers, asset sales, dividends, investments, affiliate transactions and restrictions on commodity hedging. During the continuance of certain events of default, the lenders may take a number of actions, including declaring the entire amount then outstanding under the Amended Credit Agreement due and payable (in the event of certain insolvency-related events, the entire amount then outstanding under the Amended Credit Agreement will become automatically due and payable). The Amended Credit Agreement also requires maintenance of certain financial covenants, including (i) a consolidated funded debt to EBITDA ratio of not more than 2.75x 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 December 31, 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

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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 approximately $11.8 million term loan agreement, the Building Loan, maturing on November 20, 2030. There were no changes to the terms of the Building Loan pursuant to the Plan. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $73,000 commencing on December 20, 2015. As of December 31, 2017, the outstanding balance under the Building Loan totaled $10.9 million.

The Building Loan is collateralized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. We were in compliance with all covenants under the Building Loan as of December 31, 2017.

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 million of the Company’s 2022 Second Lien Notes pursuant thereto.

Interest on the 2022 Second Lien Notes accrues 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 December 31, 2017, $1.4 million had been accrued in connection with the May 31, 2018 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 are 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 are 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 as of the Effective Date 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;

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(ii) 105.625% for the twelve-month period beginning on May 31, 2021; and (iii) 100.000% for the twelve-month period beginning on May 31, 2022 and at any time thereafter, in each case, 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 (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 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 year ended December 31, 2016 (Predecessor), we recognized $15.4 million of interest expense for the amortization of the discount and $1.5 million of interest expense for the amortization of debt issuance

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costs related to the 2017 Convertible Notes. During the year ended December 31, 2015 (Predecessor), we recognized $15.0 million of interest expense for the amortization of the discount and $1.4 million of interest expense for the amortization of debt issuance costs related to 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 the 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.

Deferred Financing Cost and Interest Cost

In accordance with the provisions of ASC 852, we recognized a charge of approximately $8.3 million to write-off the remaining unamortized debt issuance costs, discounts and premiums related to the 2017 Convertible Notes and 2022 Notes, which is included in reorganization items in the accompanying consolidated statement of operations for the year ended December 31, 2016 (Predecessor). Additionally, we recognized a charge of approximately $2.6 million to write-off the remaining unamortized debt issuance costs related to the Pre-Emergence Credit Agreement as of the Petition Date, which is included in reorganization items in the consolidated statement of operations during the period from January 1, 2017 through February 28, 2017 (Predecessor). See Note 1 – Organization and Summary of Significant Accounting Policies and Note 3 – Fresh Start Accounting for additional details.

At December 31, 2017 (Successor) and December 31, 2016 (Predecessor), approximately $59 thousand and $63 thousand, respectively, of unamortized debt issuance costs were deducted from the carrying amount of the Building Loan. At December 31, 2016 (Predecessor), approximately $2.8 million of debt issuance costs related to the Pre-Emergence Credit Agreement were classified as other assets.

Prior to the filing of the Bankruptcy Petitions, the costs associated with the 2017 Convertible Notes were being amortized over the life of the notes using a method that applied an effective interest rate of 7.51%. The costs associated with the November 2012 issuance and November 2013 issuance of the 2022 Notes were being amortized over the life of the notes using a method that applied effective interest rates of 7.75% and 7.04%, respectively. The costs associated with the Pre-Emergence Credit Agreement were being amortized on a straight-line basis over the term of the facility. The costs associated with the issuance of the Building Loan are being amortized using the effective interest method over the term of the Building Loan.

Total interest cost incurred, before capitalization, on all obligations for the period from March 1, 2017 through December 31, 2017 (Successor) was $15.7 million. Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2016 and 2015 (Predecessor) was $91.1 million and $85.3 million, respectively. In accordance with the accounting guidance in ASC 852, we accrued interest on the 2017 Convertible Notes and 2022 Notes only up to the Petition Date, and such amounts were included as liabilities subject to compromise in our consolidated balance sheet at December 31, 2016 (Predecessor). Accordingly, there was no interest expense recognized on the 2017 Convertible Notes or the 2022 Notes after the Bankruptcy Petitions were filed.

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 December 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (Predecessor), we entered into various commodity derivative contracts (see Note 9 –

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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 of these derivative contracts will be recorded in earnings through derivative income (expense).

During the year ended December 31, 2016, we reclassified a $6.1 million loss related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC.

The following tables include the changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2016 and 2015 (Predecessor) (in thousands):


	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2016 (Predecessor)
Beginning balance, net of tax	$	24,025		$	(6,073	)	$	17,952

Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		(1,648	)		—			(1,648	)
Foreign currency translations		—			(8	)		(8	)
Income tax effect		581			—			581

Net of tax		(1,067	)		(8	)		(1,075	)

Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production		35,457			—			35,457
Other operational expenses		—			(6,081	)		(6,081	)
Income tax effect		(12,499	)		—			(12,499	)

Net of tax		22,958			(6,081	)		16,877

Other comprehensive income (loss), net of tax		(24,025	)		6,073			(17,952	)

Ending balance, net of tax	$	—		$	—		$	—


	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2015 (Predecessor)
Beginning balance, net of tax	$	86,783		$	(3,468	)	$	83,315

Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		52,630			—			52,630
Foreign currency translations		—			(2,605	)		(2,605	)
Income tax effect		(19,096	)		—			(19,096	)

Net of tax		33,534			(2,605	)		30,929

Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production		149,955			—			149,955
Derivative income, net		1,170			—			1,170
Income tax effect		(54,833	)		—			(54,833	)

Net of tax		96,292			—			96,292

Other comprehensive loss, net of tax		(62,758	)		(2,605	)		(65,363	)

Ending balance, net of tax	$	24,025		$	(6,073	)	$	17,952

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NOTE 15 — EMPLOYEE BENEFIT PLANS

We entered into deferred compensation and disability agreements with certain of our former officers. The benefits under the deferred compensation agreements vested after certain periods of employment, and at December 31, 2017 (Successor), the liability for such vested benefits was approximately $0.9 million and is recorded in current and other long-term liabilities. The deferred compensation plan is described further below.

The following is a brief description of each incentive compensation plan applicable to our employees:

Annual Incentive Cash Compensation Plans

In 2016, we replaced our historical long-term cash and equity-based incentive compensation programs with the 2016 Performance Incentive Compensation Plan (the “2016 Annual Incentive Plan”), pursuant to which incentive cash bonuses were calculated based on the achievement of certain strategic objectives for each quarter of 2016. 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 short-term cash 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 Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, and the 2016 Annual Incentive Plan.

For the period from March 1, 2017 through December 31, 2017 (Successor), Stone incurred expenses of $7.0 million, net of amounts capitalized, related to incentive compensation cash bonuses. Stone incurred expenses of $13.5 million and $2.2 million, net of amounts capitalized, for each of the years ended December 31, 2016 and 2015 (Predecessor), respectively, related to incentive compensation cash bonuses. These charges are reflected in incentive compensation expense on the statement of operations.

Key Executive Incentive Plan

Pursuant to the terms of the Executive Claims Settlement Agreement, the Company’s executives agreed to waive their claims related to the Company’s 2016 Annual Incentive Plan, 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. Payments to the Company’s executives under the KEIP were limited to $2.0 million, or the equivalent of the target bonus under the 2016 Annual Incentive Plan for the fourth quarter of 2016. The KEIP payments of $2.0 million are reflected in incentive compensation expense on the statement of operations for the period from January 1, 2017 through February 28, 2017 (Predecessor).

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 $1.0 million for the period from March 1, 2017 through December 31, 2017 (Successor), representing a prorated portion of estimated retention awards through December 31, 2017. This charge is reflected in incentive compensation expense on the statement of operations.

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Transaction Bonus Agreement

On November 21, 2017, the Board approved transaction bonuses and the form of Stone Energy Corporation Transaction Bonus Agreement (the “Transaction Bonus Agreement”) and authorized the Company to enter into Transaction Bonus Agreements with certain of our executive officers and other employees of the Company. The Transaction Bonus Agreements provide for a lump sum cash payment within 30 days of a “change in control” (as defined in the Transaction Bonus Agreement) if the individual remains employed with the Company through the date of the “change in control” or is terminated prior to the change in control (i) due to death, (ii) by the Company without “cause” (as defined below) (including due to disability), or (iii) by the individual for “good reason” (as defined in the Transaction Bonus Agreement). The Transaction Bonus Agreements were entered into in connection with the Talos combination.

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 the 2017 LTIP is 2,614,379. As of March 9, 2018, other than the grant of 62,137 restricted stock units to the Board (see Note 16 – Share-Based Compensation), there have been no other issuances or awards of stock under the 2017 LTIP.

401(k) and Deferred Compensation Plans

The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the period from March 1, 2017 through December 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), Stone contributed $0.6 million and $0.3 million, respectively, to the plan. For the years ended December 31, 2016 and 2015 (Predecessor), Stone contributed $1.2 million and $1.6 million, respectively, to the plan.

The Stone Energy Corporation Deferred Compensation Plan (the “Deferred Compensation Plan”) provides eligible executives and employees with the option to defer up to 100% of their eligible compensation for a calendar year. Historically, we could, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by our Board. In 2016, the compensation committee of the Predecessor board adopted an amendment to the Deferred Compensation Plan that removed our ability to make matching contributions under such plan. Our Board may still elect to make discretionary profit sharing contributions to the plan. To date, there have been no matching or discretionary profit sharing contributions made by Stone under the Deferred Compensation Plan. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At December 31, 2017 (Successor) and December 31, 2016 (Predecessor), plan assets of $5.1 million and $8.7 million, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.

Change of Control and Severance Plans

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. The Executive Severance Plan

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replaced the Stone Energy Corporation Executive Severance Plan dated December 13, 2016. 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, at a cost to the participant that is equal to the cost for an active employee for similar coverage, (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 was amended on November 21, 2017 in connection with the proposed Talos combination to provide, among other things, that if a participant in the plan experiences a qualifying termination of employment during the twelve month period following Closing, such participant’s target bonus will be no less than such participant’s target bonus for the 2017 calendar year.

On July 25, 2017, the Board approved the Stone Energy Corporation Employee Severance Plan (the “2017 Employee Severance Plan”). The 2017 Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the twelve-month period following a change of control. Employees who are terminated within the scope of the 2017 Employee Severance Plan will be entitled to certain payments and benefits including the following: (i) a lump sum equal to (1) weekly pay times full years of service, plus (2) one week’s pay for each full $10 thousand of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay, (ii) continued health plan coverage for 6 months at a cost to the participant that is equal to the cost for an active employee for similar coverage, (iii) a prorated portion of the employee’s targeted bonus for the year, and (iv) reasonable outplacement services consistent with current HR practices. The 2017 Employee Severance Plan was amended on November 21, 2017 in connection with the proposed Talos combination to provide, among other things, that if a participant in the plan experiences a qualifying termination of employment during the twelve month period following Closing, such participant’s target bonus will be no less than such participant’s target bonus for the 2017 calendar year. The 2017 Employee Severance Plan replaced the Stone Energy Corporation Employee Change of Control Severance Plan, dated December 7, 2007.

NOTE 16 — SHARE-BASED COMPENSATION

On the Effective Date, pursuant to the Plan, the 2017 LTIP became effective. As discussed in Note 15 – Employee Benefit Plans, 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.

We record share-based compensation expense for share-based compensation awards based on the fair value on the date of grant. Compensation expense for share-based compensation awards is recognized in our statement of operations on a straight-line basis over the vesting period of the award. Under the full cost method of accounting, we capitalize a portion of employee and general and administrative costs (including share-based compensation). Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash provided by operating activities in our statement of cash flows. The capitalized portion is not included in net cash used in investing activities.

Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital and/or an increase in income tax expense, depending on the pool of available excess tax benefits to offset such deficit. There were no adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting in 2017, 2016 or 2015. During the period from March 1, 2017 through December 31, 2017 (Successor),

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the period from January 1, 2017 through February 28, 2017 (Predecessor) and the years ended December 31, 2016 and 2015 (Predecessor), respectively, $2.5 million, $2.7 million, $4.1 million and $1.3 million of tax deficits were charged to income tax expense.

Predecessor Share-Based Compensation

For the period from January 1, 2017 through February 28, 2017 (Predecessor), we incurred $3.5 million of share-based compensation expense, all of which related to stock awards and restricted stock issuances, and of which a total of approximately $0.9 million was capitalized into oil and gas properties. For the year ended December 31, 2016 (Predecessor), we incurred $11.6 million of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $3.1 million was capitalized into oil and gas properties. For the year ended December 31, 2015 (Predecessor), we incurred $17.9 million of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5.6 million was capitalized into oil and gas properties.

Stock Options. All outstanding stock options at December 31, 2016 related to executive share-based awards that were cancelled upon emergence from bankruptcy. There were no stock option grants during the period from January 1, 2017 through February 28, 2017. The following tables include Predecessor Company stock option activity during the years ended December 31, 2016 and 2015:


	Year Ended December 31, 2016 (Predecessor)
	Number of Options			Wgtd. Avg. Exercise Price		Wgtd. Avg. Term		Aggregate Intrinsic Value
Options outstanding, beginning of period		14,447		$	269.25
Granted		—			—
Exercised		—			—
Forfeited		—			—
Expired		(1,500	)		477.45

Options outstanding, end of period		12,947			245.13		1.4 years	$	—

Options exercisable, end of period		12,947			245.13		1.4 years		—

Options unvested, end of period		—			—		—		—


	Year Ended December 31, 2015 (Predecessor)
	Number of Options			Wgtd. Avg. Exercise Price		Wgtd. Avg. Term		Aggregate Intrinsic Value
Options outstanding, beginning of period		20,497		$	339.36
Granted		—			—
Exercised		—			—
Forfeited		—			—
Expired		(6,050	)		506.76

Options outstanding, end of period		14,447			269.25		2.1 years	$	—

Options exercisable, end of period		14,447			269.25		2.1 years		—

Options unvested, end of period		—			—		—		—

Restricted Stock and Other Stock 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

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unrecognized compensation cost related to such awards was recognized. 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 continued in accordance with the applicable vesting provisions of the original awards (see Successor Share-Based Compensation below).

During the period from January 1, 2017 through February 28, 2017, 10,404 shares (valued at $69 thousand) of Predecessor Company stock were issued, representing grants of stock to the board of directors of the Predecessor Company. During the years ended December 31, 2016 and 2015, we issued 31,313 shares (valued at $0.3 million) and 141,872 shares (valued at $23.7 million), respectively, of Predecessor Company restricted stock or stock awards.

The following table includes Predecessor Company restricted stock and stock award activity during the period from January 1, 2017 through February 28, 2017 and the years ended December 31, 2016 and 2015:


	Predecessor
	Period from January 1, 2017 through February 28, 2017					Year Ended December 31,
	Period from January 1, 2017 through February 28, 2017					2016					2015
	Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding, beginning of period		81,090		$	205.34		180,239		$	208.17		129,848		$	299.45
Issuances		10,404			6.67		31,313			8.93		141,872			167.21
Lapse of restrictions or granting of stock awards		(73,276	)		186.37		(117,406	)		158.79		(63,745	)		296.00
Forfeitures		(194	)		169.40		(13,056	)		200.06		(27,736	)		223.80

Restricted stock outstanding, end of period		18,024		$	169.42		81,090		$	205.34		180,239		$	208.17

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Successor Share-Based Compensation

Restricted Stock and Other Stock Awards.As discussed above, upon emergence from bankruptcy, all Predecessor outstanding, unvested restricted shares held by the Company’s executives were cancelled and exchanged for proportionate shares of New Common Stock. Vesting continued in accordance with the applicable vesting provisions of the original awards, with remaining compensation expense based on the fresh start fair value of $26.95 per share (see Note 3 – Fresh Start Accounting).For the period from March 1, 2017 through December 31, 2017 (Successor), we incurred approximately $0.1 million of share-based compensation expense related to these restricted shares. The restricted stock outstanding on December 31, 2017 became fully vested on January 15, 2018. The following table includes Successor Company restricted stock and stock award activity during the period from March 1, 2017 through December 31, 2017:


	Period from March 1, 2017 through December 31, 2017
	Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding at February 28, 2017 (Predecessor)		18,024		$	169.42
Restricted stock outstanding at March 1, 2017 (Successor)		3,176		$	26.95
Issuances		—			—
Lapse of restrictions		(2,083	)		21.78
Forfeitures		—			—

Restricted stock outstanding at December 31, 2017 (Successor)		1,093		$	26.95

Restricted Stock Units. On March 1, 2017, the Board received grants of restricted stock units under the 2017 LTIP. 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. During the period from March 1, 2017 through December 31, 2017 (Successor), we incurred approximately $1.2 million of share-based compensation expense related to these restricted stock units. As of December 31, 2017, there was $0.5 million of unrecognized compensation cost related to such restricted stock units, with a current weighted average remaining vesting period of approximately four months.

NOTE 17 — 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, 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 for the period from March 1, 2017 through December 31, 2017 (Successor).

In addition to the workforce reduction costs, during the second quarter of 2017, 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 for the period from March 1, 2017 through December 31, 2017 (Successor).

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NOTE 18 — 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 period from March 1, 2017 through December 31, 2017 (Successor). Included in SG&A expenses for the period from March 1, 2017 through December 31, 2017 (Successor) is a $3.9 million success-based consulting fee incurred in connection with the federal royalty recovery.

NOTE 19 — OTHER OPERATIONAL EXPENSES

Other operational expenses for the period of March 1, 2017 through December 31, 2017 (Successor) of $3.4 million included approximately $2.1 million of stacking charges for the Pompano platform rig. For the year ended December 31, 2016 (Predecessor), other operational expenses of $55.5 million included approximately $17.7 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 $20.0 million charge related to the termination of our deep water drilling rig contract with Ensco and $9.9 million in charges related to the terminations of offshore vessel and Appalachian drilling rig contracts. Also included in other operational expenses for the year ended December 31, 2016 (Predecessor) is a $6.1 million loss on the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See Note 14 – Accumulated Other Comprehensive Income (Loss).

NOTE 20 — COMBINATION TRANSACTION COSTS

In connection with the pending combination with Talos, we have incurred approximately $6.2 million in transaction costs, consisting primarily of legal and financial advisor costs. These costs are included in SG&A expense on our statement of operations for the period from March 1, 2017 through December 31, 2017 (Successor). Additionally, we have incurred approximately $0.2 million of direct costs for purposes of registering equity securities to effect the Talos combination. These direct costs are recorded as a reduction of additional paid-in-capital during the period from March 1, 2017 through December 31, 2017 (Successor). See Note 1 – Organization and Summary of Significant Accounting Policies for more information on the pending combination.

NOTE 21 — COMMITMENTS AND CONTINGENCIES

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.

Leases

We lease office facilities in Lafayette and New Orleans, Louisiana under the terms of non-cancelable leases expiring on various dates in 2018. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net commitment for 2018 under our leases, subleases and contracts at December 31, 2017 totaled $0.3 million.

Payments related to our lease obligations were $0.5 million for the period from March 1, 2017 through December 31, 2017 (Successor) and $0.1 million for the period of January 1, 2017 through February 28, 2017 (Predecessor). Payments related to our lease obligations for the years ended December 31, 2016 and 2015 (Predecessor) were approximately $0.7 million and $3.1 million, respectively.

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Other Commitments and Contingencies

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management (“BOEM”) stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $115 million in surety bonds in favor of BOEM, third-party bonds, and letters of credit, all relating to our offshore abandonment obligations.

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

We received a self-insurance letter from BOEM dated September 30, 2016 stating that we were not eligible to self-insure any of our additional security obligations. We received a proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required. The September 30, 2016 self-insurance determination letter was rescinded by BOEM on March 24, 2017.

In the first quarter of 2017, BOEM announced that it would extend the implementation timeline for the July 2016 NTL by an additional six months. Furthermore, on April 28, 2017, President Trump issued an executive order directing the Secretary of the Interior to review the NTL to determine whether modifications are necessary to ensure operator compliance with lease terms while minimizing unnecessary regulatory burdens. On June 22, 2017, BOEM announced that, pending its review of the NTL, the implementation timeline would be indefinitely extended, subject to certain exceptions. At this time, it is uncertain when, or if, the July 2016 NTL will be implemented or whether a revised NTL might be proposed. 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, 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.

In connection with our exploration and development efforts, we are contractually committed to the acquisition of seismic data in the amount of $8.6 million to be incurred over the next two years.

The Oil Pollution Act (“OPA”) imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA and a final rule adopted by BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10 million in specified state waters to at least $35 million in Outer Continental Shelf waters, with higher amounts of up to $150 million in certain limited circumstances where BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under BOEM’s final rule. In addition, BOEM has finalized rules that raise OPA’s damages liability cap from $75 million to $133.7 million.

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NOTE 22 — SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED

At December 31, 2017 and 2016, our oil and gas properties were located in the United States (onshore and offshore). On February 27, 2017, we completed the sale of the Appalachia Properties in connection with our restructuring (see Note 4 – Divestiture). During 2015, we discontinued our business development effort in Canada.

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.

Costs Incurred

United States. The following table discloses the total amount of capitalized costs and accumulated DD&A relative to our proved and unevaluated oil and natural gas properties located in the United States (in thousands):


	Successor			Predecessor
	December 31, 2017			December 31, 2016
Proved properties	$	713,157		$	9,572,082
Unevaluated properties		102,187			373,720

Total proved and unevaluated properties		815,344			9,945,802
Less accumulated depreciation, depletion and amortization		(353,462	)		(9,134,288	)

Balance, end of year	$	461,882		$	811,514

The following table sets forth certain information regarding the costs incurred in our acquisition, exploratory and development activities in the United States during the periods indicated (in thousands):


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			2016			2015
Costs incurred during the period (capitalized):
Acquisition costs, net of sales of unevaluated properties	$	(8,371	)	$	(324	)	$	3,923		$	(14,158	)
Exploratory costs		12,079			2,055			17,891			104,169
Development costs(1)		33,356			12,547			102,665			266,982
Salaries, general and administrative costs		7,495			2,976			21,753			27,984
Interest		3,927			2,524			26,634			41,339
Less: overhead reimbursements		(1,004	)		—			(521	)		(913	)

Total costs incurred during the period, net of divestitures	$	47,482		$	19,778		$	172,345		$	425,403

(1)	Includes net changes in capitalized asset retirement costs of ($17,446), $0, ($4,461) and ($43,901), respectively.

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The following table discloses operational expenses incurred during the periods indicated relative to our oil and natural gas producing activities located in the United States (in thousands):


	Successor		Predecessor
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017		Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017		2016		2015
Lease operating expenses	$	49,800	$	8,820	$	79,650	$	100,139
Transportation, processing and gathering expenses		4,084		6,933		27,760		58,847
Production taxes		629		682		3,148		6,877
Accretion expense		21,151		5,447		40,229		25,988

Expensed costs – United States	$	75,664	$	21,882	$	150,787	$	191,851

The following table sets forth certain information relative to the amortization of our investment in oil and gas properties and the impairment of our oil and gas properties in the United States for the periods indicated (in thousands, except per unit amounts):


	Successor		Predecessor
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017		Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017		Period from January 1, 2017 through February 28, 2017		2016		2015
Provision for DD&A	$	97,027	$	36,751	$	215,737	$	277,088
Write-down of oil and gas properties	$	256,435	$	—	$	357,079	$	1,314,817
DD&A per Boe	$	16.61	$	17.05	$	16.10	$	19.15

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 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 December 31, 2017 and was primarily due to differences between the trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017. Weighted average commodity prices used in the determination of the fair value of our oil and gas properties for purposes of fresh start accounting were $56.01 per Bbl of oil, $2.52 per Mcf of natural gas and $14.18 per Bbl of NGLs, net of applicable differentials.

Since none of our derivatives as of March 31, 2017 were designated as cash flow hedges (see Note 9 – Derivative Instruments and Hedging Activities), the write-down at March 31, 2017 was not affected by hedging. The 2016 and 2015 write-downs were decreased by $50.7 million and $143.9 million, respectively, as a result of hedges.

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The following table discloses net costs incurred (evaluated) on our unevaluated properties located in the United States for the periods indicated (in thousands):


	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period from January 1, 2017 through February 28, 2017			2016			2015
Net costs incurred (evaluated) during period:
Acquisition costs	$	(9,155	)	$	959		$	(71,378	)	$	(115,767	)
Exploration costs		10,405			(6,063	)		(21,579	)		(16,315	)
Capitalized interest		3,927			2,524			26,634			41,339

	$	5,177		$	(2,580	)	$	(66,323	)	$	(90,743	)

Under fresh start accounting, our oil and gas properties were recorded at fair value as of February 28, 2017. The following table discloses financial data associated with unevaluated costs (United States) for the Successor Company at December 31, 2017 (in thousands):


	Successor		Net Costs Incurred During the Period from March 1, 2017 through December 31, 2017			Successor
	March 1, 2017					December 31, 2017
Acquisition costs	$	58,359	$	(9,155	)	$	49,204
Exploration costs		38,651		10,405			49,056
Capitalized interest		—		3,927			3,927

Total unevaluated costs	$	97,010	$	5,177		$	102,187

Approximately 34 specifically identified drilling projects are included in unevaluated costs at December 31, 2017 and are expected to be evaluated in the next four years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined.

Canada. During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Upon a more complete evaluation of this project and in response to the significant decline in commodity prices, we discontinued our business development effort in Canada during 2015 and recognized a full impairment of our Canadian oil and gas properties. The following table discloses certain financial data relative to our oil and gas activities located in Canada (in thousands):


	Predecessor
	Year Ended December 31,
	2016			2015
Oil and gas properties – Canada:
Balance, beginning of year	$	42,484		$	36,579
Costs incurred during the year (capitalized):
Acquisition costs		(498	)		(2,862	)
Exploratory costs		2,168			8,767

Total costs incurred during the year		1,670			5,905

Balance, end of year (fully evaluated at December 31, 2016 and 2015)	$	44,154		$	42,484

F-50


	Predecessor
	Year Ended December 31,
	2016			2015
Accumulated DD&A:
Balance, beginning of year	$	(42,484	)	$	—
Foreign currency translation adjustment		(1,318	)		5,146
Write-down of oil and gas properties		(352	)		(47,630	)

Balance, end of year	$	(44,154	)	$	(42,484	)

Net capitalized costs – Canada	$	—		$	—

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2017 have been prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

The following table sets forth an analysis of the estimated quantities of net proved oil (including condensate), natural gas and NGL reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil, natural gas and NGL reserves are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical twelve-month average pricing assumption.


	Oil (MBbls)			NGLs (MBbls)			Natural Gas (MMcf)			Oil, Natural Gas and NGLs (MBoe)
Estimated proved developed and undeveloped reserves:
As of December 31, 2014 (Predecessor)		42,397			27,817			493,843			152,520
Revisions of previous estimates		(6,818	)		(20,777	)		(362,102	)		(87,945	)
Extensions, discoveries and other additions		862			11			1,499			1,123
Purchase of producing properties		685			1,808			26,136			6,849
Sale of reserves		(859	)		—			(1,061	)		(1,036	)
Production		(5,991	)		(2,401	)		(36,457	)		(14,468	)

As of December 31, 2015 (Predecessor)		30,276			6,458			121,858			57,043
Revisions of previous estimates		(751	)		6,352			24,858			9,744
Extensions, discoveries and other additions		63			2			45			73
Production		(6,308	)		(2,183	)		(29,441	)		(13,398	)

As of December 31, 2016 (Predecessor)		23,280			10,629			117,320			53,462
Revisions of previous estimates		730			(2	)		1,242			935
Sale of reserves		(826	)		(7,417	)		(52,992	)		(17,075	)
Production		(908	)		(408	)		(5,037	)		(2,156	)

As of February 28, 2017 (Predecessor)		22,276			2,802			60,533			35,166
Revisions of previous estimates		3,769			(94	)		(2,801	)		3,208
Production		(4,169	)		(403	)		(7,616	)		(5,841	)

As of December 31, 2017 (Successor)		21,876			2,305			50,116			32,533

F-51


	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Oil, Natural Gas and NGLs (MBoe)
Estimated proved developed reserves:
As of December 31, 2015 (Predecessor)		21,734		4,784		90,262		41,562
As of December 31, 2016 (Predecessor)		18,269		9,255		90,741		42,647
As of February 28, 2017 (Predecessor)		18,344		1,515		35,865		25,836
As of December 31, 2017 (Successor)		20,275		1,689		37,946		28,288
Estimated proved undeveloped reserves:
As of December 31, 2015 (Predecessor)		8,542		1,674		31,596		15,481
As of December 31, 2016 (Predecessor)		5,011		1,374		26,579		10,815
As of February 28, 2017 (Predecessor)		3,932		1,287		24,668		9,330
As of December 31, 2017 (Successor)		1,601		616		12,170		4,245

The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year.

2017 Periods. Revisions of previous estimates were primarily the result of positive well performance (4 MMBoe). The sale of reserves represents the sale of the Appalachia Properties (17 MMBoe) in connection with our restructuring (see Note 4 – Divestiture).

Year Ended December 31, 2016. Revisions of previous estimates were primarily the result of positive reserve report gas pricing changes extending the economic limits of the reservoirs (15 MMBoe) primarily in Appalachia, slightly offset by negative well performance (6 MMBoe).

Year Ended December 31, 2015. Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves (95 MMBoe) primarily in Appalachia, slightly offset by positive well performance (7 MMBoe). Purchase of producing properties related to increases in our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units.

F-52

Standardized Measure of Discounted Future Net Cash Flows

The following tables present the standardized measure of discounted future net cash flows related to estimated proved oil, natural gas and NGL reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2017. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil, natural gas and NGL reserves. Prices are based on either the historical twelve-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. Our GOM Basin properties represented 100% of our estimated proved oil and natural gas reserves and standardized measure of discounted future net cash flows at December 31, 2017. The standardized measure of discounted future net cash flows and changes therein are as follows (in thousands, except average prices):


	Standardized Measure
	Successor December 31, 2017			Predecessor December 31,
	Successor December 31, 2017			2016			2015
Future cash inflows	$	1,264,809		$	1,236,097		$	1,921,329
Future production costs		(497,538	)		(480,815	)		(651,396	)
Future development costs		(431,752	)		(638,988	)		(679,355	)
Future income taxes		—			—			—

Future net cash flows		335,519			116,294			590,578
10% annual discount		57,591			109,628			13,259

Standardized measure of discounted future net cash flows	$	393,110		$	225,922		$	603,837

Average prices related to proved reserves:
Oil (per Bbl)	$	50.05		$	40.15		$	51.16
NGLs (per Bbl)		22.90			9.46			16.40
Natural gas (per Mcf)		2.34			1.71			2.19

F-53


	Changes in Standardized Measure
	Successor			Predecessor
	Period from March 1, 2017 through December 31, 2017			Period From January 1, 2017 through February 28, 2017			Year Ended December 31,
	Period from March 1, 2017 through December 31, 2017			Period From January 1, 2017 through February 28, 2017			2016			2015
Standardized measure at beginning of period	$	303,086		$	225,922		$	603,837		$	1,418,792
Sales and transfers of oil, natural gas and NGLs produced, net of production costs		(164,612	)		(46,137	)		(223,948	)		(340,477	)
Changes in price, net of future production costs		66,192			17,455			(448,861	)		(237,747	)
Extensions and discoveries, net of future production and development costs		—			—			5,243			1,573
Changes in estimated future development costs, net of development costs incurred during the period		88,111			20,756			54,406			731,115
Revisions of quantity estimates		96,454			36,557			139,759			(1,458,652	)
Accretion of discount		30,309			22,592			60,384			174,456
Net change in income taxes		—			—			—			325,768
Purchases of reserves in-place		—			—			—			3,493
Sales of reserves in-place		—			14,584			—			—
Changes in production rates due to timing and other		(26,430	)		11,357			35,102			(14,484	)

Net change in standardized measure		90,024			77,164			(377,915	)		(814,955	)

Standardized measure at end of period	$	393,110		$	303,086		$	225,922		$	603,837

NOTE 23 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED

The Company’s results of operations by quarter are as follows (in thousands, except per share amounts):


	Predecessor			Successor
	Period from January 1, 2017 through February 28, 2017			Period from March 1, 2017 through March 31, 2017			2017 Quarter Ended
	Period from January 1, 2017 through February 28, 2017			Period from March 1, 2017 through March 31, 2017			June 30			Sept. 30			Dec. 31
Operating revenue	$	68,922		$	25,809		$	76,722		$	79,525		$	76,327
Income (loss) from operations	$	209,119		$	(258,594	)	$	(4,519	)	$	2,653		$	5,302
Net income (loss)	$	630,317		$	(259,613	)	$	(6,461	)	$	1,297		$	17,138
Basic income (loss) per share	$	110.99		$	(12.98	)	$	(0.32	)	$	0.06		$	0.86
Diluted income (loss) per share	$	110.99		$	(12.98	)	$	(0.32	)	$	0.06		$	0.86
Write-down of oil and gas properties	$	—		$	256,435		$	—		$	—		$	—
Gain (loss) on Appalachia Properties divestiture	$	213,453		$	—		$	27		$	(132	)	$	—
Reorganization items(1)	$	(437,744	)	$	—		$	—		$	—		$	—
Other expense	$	13,336		$	—		$	814		$	47		$	369

F-54

(1)	See Note 3 – Fresh Start Accounting for additional details.


	Predecessor 2016 Quarter Ended
	March 31			June 30			Sept. 30			Dec. 31
Operating revenue	$	80,677		$	89,319		$	94,427		$	113,107
Loss from operations	$	(172,150	)	$	(174,656	)	$	(72,128	)	$	(90,234	)
Net loss	$	(188,784	)	$	(195,761	)	$	(89,635	)	$	(116,406	)
Basic loss per share	$	(33.89	)	$	(35.05	)	$	(16.01	)	$	(20.76	)
Diluted loss per share	$	(33.89	)	$	(35.05	)	$	(16.01	)	$	(20.76	)
Write-down of oil and gas properties	$	129,204		$	118,649		$	36,484		$	73,094
Restructuring fees	$	953		$	9,436		$	5,784		$	13,424
Other operational expenses(1)	$	12,527		$	27,680		$	9,059		$	6,187
Reorganization items	$	—		$	—		$	—		$	10,947

(1)	See Note 19 – Other Operational Expenses for additional details.

NOTE 24 — 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.

F-55

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET

(In thousands of dollars)


	Successor
	March 31, 2018			December 31, 2017
	(Unaudited)			(Note 1)
Assets
Current assets:
Cash and cash equivalents	$	277,842		$	263,495
Restricted cash		—			18,742
Accounts receivable		36,378			39,258
Fair value of derivative contracts		417			879
Current income tax receivable		16,212			36,260
Other current assets		6,901			7,138

Total current assets		337,750			365,772
Oil and gas properties, full cost method of accounting:
Proved		713,304			713,157
Less: accumulated depreciation, depletion and amortization		(374,063	)		(353,462	)

Net proved oil and gas properties		339,241			359,695
Unevaluated		118,365			102,187
Other property and equipment, net		16,544			17,275
Other assets, net		14,066			13,844

Total assets	$	825,966		$	858,773

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	20,088		$	54,226
Undistributed oil and gas proceeds		4,283			5,142
Accrued interest		6,038			1,685
Fair value of derivative contracts		13,147			8,969
Asset retirement obligations		56,428			79,300
Current portion of long-term debt		430			425
Other current liabilities		13,552			22,579

Total current liabilities		113,966			172,326
Long-term debt		235,394			235,502
Asset retirement obligations		140,226			133,801
Fair value of derivative contracts		4,564			3,085
Other long-term liabilities		5,743			5,891

Total liabilities		499,893			550,605

Commitments and contingencies
Stockholders’ equity:
Common stock ($.01 par value; authorized 60,000,000 shares; issued 19,998,701 and 19,998,019 shares, respectively)		200			200
Additional paid-in capital		555,940			555,607
Accumulated deficit		(230,067	)		(247,639	)

Total stockholders’ equity		326,073			308,168

Total liabilities and stockholders’ equity	$	825,966		$	858,773

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

F-56

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


	Successor						Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017
Operating revenue:
Oil production	$	73,261		$	20,027		$	45,837
Natural gas production		4,900			2,210			13,476
Natural gas liquids production		3,188			777			8,706
Other operational income		27			149			903
Derivative income, net		—			2,646			—

Total operating revenue		81,376			25,809			68,922

Operating expenses:
Lease operating expenses		14,380			4,740			8,820
Transportation, processing and gathering expenses		783			144			6,933
Production taxes		(2,201	)		65			682
Depreciation, depletion and amortization		21,333			15,847			37,429
Write-down of oil and gas properties		—			256,435			—
Accretion expense		4,287			2,901			5,447
Salaries, general and administrative expenses		12,556			3,322			9,629
Incentive compensation expense		387			—			2,008
Restructuring fees		—			288			—
Other operational expenses		179			661			530
Derivative expense, net		9,548			—			1,778

Total operating expenses		61,252			284,403			73,256

Gain on Appalachia Properties divestiture		—			—			213,453

Income (loss) from operations		20,124			(258,594	)		209,119

Other (income) expense:
Interest expense		3,537			1,190			—
Interest income		(1,539	)		(40	)		(45	)
Other income		(203	)		(131	)		(315	)
Other expense		21			—			13,336
Reorganization items, net		—			—			(437,744	)

Total other (income) expense		1,816			1,019			(424,768	)

Income (loss) before income taxes		18,308			(259,613	)		633,887

Provision (benefit) for income taxes:
Current		—			—			3,570

Total income taxes		—			—			3,570

Net income (loss)	$	18,308		$	(259,613	)	$	630,317

Basic income (loss) per share	$	0.91		$	(12.98	)	$	110.99
Diluted income (loss) per share	$	0.91		$	(12.98	)	$	110.99
Average shares outstanding		19,998			19,997			5,634
Average shares outstanding assuming dilution		19,998			19,997			5,634

The accompanying notes are an integral part of this statement.

F-57

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)


	Common Stock			Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Total Stockholders’ Equity
Balance, December 31, 2016 (Predecessor)	$	56		$	(860	)	$	1,659,731		$	(2,296,209	)	$	(637,282	)
Net income		—			—			—			630,317			630,317
Lapsing of forfeiture restrictions 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			—			554,537			—			554,737
Balance, February 28, 2017 (Successor)		200			—			554,537			—			554,737
Net loss		—			—			—			(247,639	)		(247,639	)
Lapsing of forfeiture restrictions of restricted stock		—			—			(19	)		—			(19	)
Amortization of stock compensation expense		—			—			1,272			—			1,272
Stock issuance costs - Talos combination		—			—			(183	)		—			(183	)

Balance, December 31, 2017 (Successor)		200			—			555,607			(247,639	)		308,168
Cumulative effect adjustment (see Note 13)		—			—			—			(736	)		(736	)
Net income		—			—			—			18,308			18,308
Lapsing of forfeiture restrictions of restricted stock		—			—			(15	)		—			(15	)
Amortization of stock compensation expense		—			—			348			—			348

Balance, March 31, 2018 (Successor)	$	200		$	—		$	555,940		$	(230,067	)	$	326,073

The accompanying notes are an integral part of this statement.

F-58

STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)


	Successor						Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017
Cash flows from operating activities:
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		21,333			15,847			37,429
Write-down of oil and gas properties		—			256,435			—
Accretion expense		4,287			2,901			5,447
Gain on sale of oil and gas properties		—			—			(213,453	)
Settlement of asset retirement obligations		(20,734	)		(17,600	)		(3,641	)
Non-cash stock compensation expense		348			17			2,645
Non-cash derivative (income) expense		6,119			(2,484	)		1,778
Non-cash interest expense		1			—			—
Non-cash reorganization items		—			—			(458,677	)
Other non-cash expense		22			—			172
Change in current income taxes		20,049			—			3,570
Decrease in accounts receivable		2,144			6,728			6,354
(Increase) decrease in other current assets		237			964			(2,274	)
Increase (decrease) in accounts payable		(13,701	)		3,015			(4,652	)
Increase (decrease) in other current liabilities		(5,534	)		1,672			(9,653	)
Investment in derivative contracts		—			(2,140	)		(3,736	)
Other		(393	)		4,904			2,490

Net cash provided by (used in) operating activities		32,486			10,646			(5,884	)

Cash flows from investing activities:
Investment in oil and gas properties		(37,081	)		(5,584	)		(8,754	)
Proceeds from sale of oil and gas properties, net of expenses		320			10,770			505,383
Investment in fixed and other assets		—			(2	)		(61	)

Net cash provided by (used in) investing activities		(36,761	)		5,184			496,568

Cash flows from financing activities:
Repayments of bank borrowings		—			—			(341,500	)
Repayments of building loan		(105	)		(36	)		(24	)
Cash payment to noteholders		—			—			(100,000	)
Debt issuance costs		—			—			(1,055	)
Net payments for share-based compensation		(15	)		—			(173	)

Net cash used in financing activities		(120	)		(36	)		(442,752	)

Net change in cash, cash equivalents and restricted cash		(4,395	)		15,794			47,932
Cash, cash equivalents and restricted cash, beginning of period		282,237			238,513			190,581

Cash, cash equivalents and restricted cash, end of period	$	277,842		$	254,307		$	238,513

The accompanying notes are an integral part of this statement.

F-59

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 March 31, 2018 (Successor) and for the three months ended March 31, 2018 (Successor) and the periods from March 1, 2017 through March 31, 2017 (Successor) and January 1, 2017 through February 28, 2017 (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, 2017 (Successor) has been derived from the audited financial statements as of that date contained in our financial statements for the year ended December 31, 2017. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, 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 three months ended March 31, 2018 (Successor) are not necessarily indicative of future financial results. Certain prior period amounts have been reclassified to conform to current period presentation.

Pending Combination with Talos

Stone, Sailfish Energy Holdings Corporation (“New Talos”), a direct wholly owned subsidiary of Stone, and Sailfish Merger Sub Corporation, a direct wholly owned subsidiary of New Talos, entered into a Transaction Agreement (the “Transaction Agreement”) with Talos on November 21, 2017, which contemplates a series of transactions (the “Transactions”) occurring on the date of closing of the Transaction Agreement (the “Closing”) that will result in such business combination. Stone and Talos will become wholly owned subsidiaries of New Talos. At the time of the Closing, the parties intend that New Talos will become a publicly traded entity named Talos Energy Inc. The Transactions include (i) the contribution of 100% of the equity interests in Talos Production to New Talos in exchange for shares of New Talos common stock, (ii) the contribution by entities controlled by or affiliated with Apollo Management (the “Apollo Funds”) and Riverstone (the “Riverstone Funds”) of $102 million in aggregate principal amount of 9.75% Senior Notes due 2022 issued by Talos Production and Talos Production Finance Inc. (together, the “the Talos Issuers”) to New Talos in exchange for shares of New Talos common stock, (iii) the exchange of the second lien bridge loans due 2022 issued by the Talos Issuers for newly issued 11.0% second lien notes issued by the Talos Issuers, and (iv) the exchange of the 7.50% Senior Second Lien Notes due 2022 (the “2022 Second Lien Notes”) issued by Stone for newly issued 11.0% second lien notes issued by the Talos Issuers.

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Talos common stock and Talos Energy stakeholders will hold 63% of the outstanding New Talos common stock. Outstanding warrants to acquire Stone common stock will become warrants to acquire New Talos common stock with terms and conditions substantially identical to their existing terms and conditions. The combination was unanimously approved by the boards of directors of Stone and Talos Energy.

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

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

The combination is expected to close on or about May 10, 2018. We cannot provide any assurance that the combination will be completed on the terms or timeline currently contemplated, or at all. The above is a summary of the material terms of the Transactions and is qualified in its entirety by reference to the New Talos Registration Statement on Form S-4 (which became effective on April 9, 2018).

Reorganization and Emergence from Voluntary Reorganization Under Chapter 11 Proceedings

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

Upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification (“ASC”) 852, “Reorganizations”, which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. As a result of the adoption of fresh start accounting, the Company’s unaudited condensed consolidated financial statements subsequent to February 28, 2017 will not be comparable to its financial statements prior to that date. See Note 3 – Fresh Start Accounting for further details on the impact of fresh start accounting on the Company’s unaudited condensed consolidated financial statements. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to “Predecessor” or “Predecessor Company” relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

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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.

Recently Adopted Accounting Standards

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

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

Recently Issued Accounting Standards

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NOTE 2 – REORGANIZATION

In connection with our reorganization, we sold certain producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the “Appalachia Properties”) to EQT Corporation, through its wholly-owned subsidiary EQT Production Company (“EQT”), 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, as described below. Additionally, the Company used a portion of the cash consideration received to pay TH Exploration III, LLC, an affiliate of Tug Hill, Inc. (“Tug Hill”), a break-up fee and expense reimbursements totaling approximately $11.5 million related to the termination of a purchase and sale agreement for the Appalachia Properties prior to the sale to EQT. See Note 5 – 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:

•

The Predecessor Company’s 7¹⁄₂% Senior Notes due 2022 (the “2022 Notes”) and 1³⁄₄% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) were cancelled and the holders of such notes received their pro rata share of (a) $100 million of cash, (b) 19.0 million shares of the New Common Stock, representing 95% of the New Common Stock and (c) $225 million of 2022 Second Lien Notes.

•

The Predecessor Company’s 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”) was amended and restated as the Amended Credit Agreement (as defined in Note 8 – Debt). The obligations owed to the lenders under the Pre-Emergence Credit Agreement were converted to obligations under the Amended Credit Agreement

•

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

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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.

Valuation of Assets

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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.


	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets		371,278
Less: Fair value of debt		(236,261	)
Less: Fair value of warrants		(15,648	)

Fair value of Successor common stock	$	539,089

Shares issued upon emergence		20,000
Per share value	$	26.95

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


	February 28, 2017
Enterprise value	$	419,720
Plus: Cash and other assets		371,278
Plus: Asset retirement obligations (current and long-term)		290,067
Plus: Working capital and other liabilities		58,055

Reorganization value of Successor assets	$	1,139,120

Condensed Consolidated Balance Sheet

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	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments					Successor Company
Assets
Current assets:
Cash and cash equivalents	$	198,571		$	(35,605	)	(1)	$	—				$	162,966
Restricted cash		—			75,547		(1)		—					75,547
Accounts receivable		42,808			9,301		(2)		—					52,109
Fair value of derivative contracts		1,267			—				—					1,267
Current income tax receivable		22,516			—				—					22,516
Other current assets		11,033			875		(3)		(124	)	(12	)		11,784

Total current assets		276,195			50,118				(124	)				326,189
Oil and gas properties, full cost method of accounting:
Proved		9,633,907			(188,933	)	(1)		(8,774,122	)	(12	)		670,852
Less: accumulated DD&A		(9,215,679	)		—				9,215,679		(12	)		—

Net proved oil and gas properties		418,228			(188,933	)			441,557					670,852
Unevaluated		371,140			(127,838	)	(1)		(146,292	)	(12	)		97,010
Other property and equipment, net		25,586			(101	)	(4)		(4,423	)	(13	)		21,062
Fair value of derivative contracts		1,819			—				—					1,819
Other assets, net		26,516			(4,328	)	(5)		—					22,188

Total assets	$	1,119,484		$	(271,082	)		$	290,718				$	1,139,120

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	20,512		$	—			$	—				$	20,512
Undistributed oil and gas proceeds		5,917			(4,139	)	(1)		—					1,778
Accrued interest		266			—				—					266
Asset retirement obligations		92,597			—				—					92,597
Fair value of derivative contracts		476			—				—					476
Current portion of long-term debt		411			—				—					411
Other current liabilities		17,032			(195	)	(6)		—					16,837

Total current liabilities		137,211			(4,334	)			—					132,877
Long-term debt		352,350			(116,500	)	(7)		—					235,850
Asset retirement obligations		151,228			(8,672	)	(1)		54,914		(14)			197,470
Fair value of derivative contracts		653			—				—					653
Other long-term liabilities		17,533			—				—					17,533

Total liabilities not subject to compromise		658,975			(129,506	)			54,914					584,383
Liabilities subject to compromise		1,110,182			(1,110,182	)	(8)		—					—

Total liabilities		1,769,157			(1,239,688	)			54,914					584,383

Commitments and contingencies Stockholders’ equity:
Common stock (Predecessor)		56			(56	)	(9)		—					—
Treasury stock (Predecessor)		(860	)		860		(9)		—					—
Additional paid-in capital (Predecessor)		1,660,810			(1,660,810	)	(9)		—					—
Common stock (Successor)		—			200		(10)		—					200
Additional paid-in capital (Successor)		—			554,537		(10)		—					554,537
Accumulated deficit		(2,309,679	)		2,073,875		(11)		235,804		(15)			—

Total stockholders’ equity		(649,673	)		968,606				235,804					554,737

Total liabilities and stockholders’ equity	$	1,119,484		$	(271,082	)		$	290,718				$	1,139,120

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Reorganization Adjustments


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 5 – Divestiture for additional details on the sale. Total consideration received for the sale of the Appalachia Properties of $522.5 million included cash consideration of $512.5 million received at closing and a $10.0 million indemnity escrow which was released subsequent to emergence from bankruptcy (see Reorganization Adjustments item number 2 below).

(b)

Reflects the movement of $75.0 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the provisions of the Amended Credit Agreement (as defined in Note 8 – Debt), and $0.5 million held in a restricted cash account for certain cure amounts in connection with the Chapter 11 proceedings.

(c)

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

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

Reflects the write-off of $2.6 million of unamortized debt issuance costs related to the Pre-Emergence Credit Agreement and the reversal of a $1.8 million prepayment made to Tug Hill in October 2016.

Reflects the accrual of $2.0 million in expected bonus payments under the Key Executive Incentive Plan and a $0.4 million termination fee in connection with the early termination of an office lease, less the settlement of a property tax accrual of $2.6 million in connection with the sale of the Appalachia Properties.

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Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):


1³⁄₄% Senior Convertible Notes due 2017	$	300,000
7¹⁄₂% Senior Notes due 2022		775,000
Accrued interest		35,182

Liabilities subject to compromise of the Predecessor Company		1,110,182
Cash payment to senior noteholders		(100,000	)
Issuance of 2022 Second Lien Notes to former holders of the senior notes		(225,000	)
Fair value of equity issued to unsecured creditors		(539,089	)
Fair value of warrants issued to unsecured creditors		(15,648	)

Gain on settlement of liabilities subject to compromise	$	230,445

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

10.

11.

Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):


Gain on settlement of liabilities subject to compromise	$	230,445
Professional and other fees paid at emergence		(10,648	)
Write-off of unamortized debt issuance costs		(2,577	)
Other reorganization adjustments		(1,915	)

Net impact to reorganization items		215,305
Gain on sale of Appalachia Properties		213,453
Cancellation of Predecessor Company equity		1,662,282
Other adjustments to accumulated deficit		(17,165	)

Net impact to accumulated deficit	$	2,073,875

Fresh Start Adjustments

12.

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

13.

14.

15.

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

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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	$	230,445
Fresh start valuation adjustments		235,804
Reorganization professional fees and other expenses		(20,403	)
Write-off of unamortized debt issuance costs		(2,577	)
Other reorganization items		(5,525	)

Gain on reorganization items, net	$	437,744

NOTE 4 – EARNINGS PER SHARE

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


	Successor						Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017			Period from January 1, 2017 through February 28, 2017
Income (numerator):
*Basic:*
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Net income attributable to participating securities		(57	)		—			(4,995	)

Net income (loss) attributable to common stock - basic	$	18,251		$	(259,613	)	$	625,322

*Diluted:*
Net income (loss)	$	18,308		$	(259,613	)	$	630,317
Net income attributable to participating securities		(56	)		—			(4,995	)

Net income (loss) attributable to common stock - diluted	$	18,252		$	(259,613	)	$	625,322

Weighted average shares (denominator):
Weighted average shares - basic		19,998			19,997			5,634
Dilutive effect of stock options		—			—			—
Dilutive effect of warrants		—			—			—
Dilutive effect of convertible notes		—			—			—

Weighted average shares - diluted		19,998			19,997			5,634

Basic income (loss) per share	$	0.91		$	(12.98	)	$	110.99

Diluted income (loss) per share	$	0.91		$	(12.98	)	$	110.99

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 March 31, 2018 (Successor), all outstanding warrants (approximately 3.5 million) were considered antidilutive because the exercise price of the warrants exceeded the average price of our common stock for the applicable period. For the period of March 1, 2017 through March 31, 2017 (Successor), all outstanding warrants (approximately 3.5 million) were antidilutive because we had a net loss for such period.

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

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During the three months ended March 31, 2018 (Successor), 682 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 period from March 1, 2017 through March 31, 2017 (Successor), we had no issuances of shares of our common stock. During the period from January 1, 2017 through February 28, 2017 (Predecessor), 47,390 shares of Predecessor Company common stock 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 5 – DIVESTITURE

On February 27, 2017, we completed the sale of the Appalachia Properties to EQT for net cash consideration of approximately $522.5 million. We no longer have assets or operations in Appalachia. Since accounting for the sale of these oil and gas properties as a reduction of the capitalized costs of oil and gas properties would have significantly altered the relationship between capitalized costs and reserves, we recognized a gain on the sale of $213.5 million during the period from January 1, 2017 through February 28, 2017 (Predecessor), computed as follows (in thousands):


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

Gain on sale		$	213,453

NOTE 6 – INVESTMENT IN OIL AND GAS PROPERTIES

Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for 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, 2018 (Successor), the present value of the estimated future net cash flows from proved reserves was based on twelve-month average prices, net of applicable differentials, of $53.04 per Bbl of oil, $2.28 per Mcf of natural gas and $25.27 per Bbl of natural gas liquids (“NGLs”). Using these prices, the Company’s net capitalized costs of proved oil and natural gas properties at March 31, 2018 (Successor) did not exceed the ceiling amount.

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 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 March 31, 2017 and was primarily due to differences between the trailing twelve-month average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017. Weighted

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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 7 – Derivative Instruments and Hedging Activities), the write-down at March 31, 2017 was not affected by hedging.

NOTE 7 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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. 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 of these derivative contracts have been, or will be, recorded in earnings through derivative income (expense).

We have entered into put contracts, fixed-price swaps and collar contracts with various counterparties for a portion of our expected 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 May 7, 2018, our derivative instruments were with four 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 are based on the NYMEX price for the last day of a respective contract month.

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


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


		Fixed-Price Swaps (NYMEX)
		Oil
		Daily Volume (Bbls/d)		Swap Price ($ per Bbl)
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
2019	January - December		2,000		56.13


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

Derivatives not designated or not qualifying as hedging instruments

The following tables disclose the location and fair value amounts of derivatives not designated or not qualifying as hedging instruments, as reported in our balance sheet, at March 31, 2018 (Successor) and December 31, 2017 (Successor) (in thousands).


Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
March 31, 2018
(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	$	417	Current liabilities: Fair value of derivative contracts	$	13,147
	Long-term assets: Fair value of derivative contracts		—	Long-term liabilities: Fair value of derivative contracts		4,564

		$	417		$	17,711

Fair Value of Derivatives Not Designated or Not Qualifying as Hedging Instruments at
December 31, 2017
(Successor)
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	879	Current liabilities: Fair value of derivative contracts	$	8,969
	Long-term assets: Fair value of derivative contracts		—	Long-term liabilities: Fair value of derivative contracts		3,085

		$	879		$	12,054

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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 March 31, 2018 (Successor), the period from January 1, 2017 through February 28, 2017 (Predecessor) and the period from March 1, 2017 through March 31, 2017 (Successor) (in thousands).


Gain (Loss) Recognized in Derivative Income (Expense)
	Successor					Predecessor
	Three Months Ended March 31, 2018			Period from March 1, 2017 through March 31, 2017		Period from January 1, 2017 through February 28, 2017
Description
Commodity contracts:
Cash settlements	$	(3,429	)	$	161	$	—
Change in fair value		(6,119	)		2,485		(1,778	)

Total gains (losses) on derivatives not designated or not qualifying as hedging instruments	$	(9,548	)	$	2,646	$	(1,778	)

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 tables present the potential impact of the offset rights associated with our recognized assets and liabilities at March 31, 2018 (Successor) and December 31, 2017 (Successor) (in thousands):


	March 31, 2018 (Successor)
	As Presented Without Netting			Effects of Netting			With Effects of Netting
Current assets: Fair value of derivative contracts	$	417		$	(417	)	$	—
Long-term assets: Fair value of derivative contracts		—			—			—
Current liabilities: Fair value of derivative contracts		(13,147	)		417			(12,730	)
Long-term liabilities: Fair value of derivative contracts		(4,564	)		—			(4,564	)


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

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NOTE 8 – DEBT

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


	Successor
	March 31, 2018			December 31, 2017
7¹⁄₂% Senior Second Lien Notes due 2022	$	225,000		$	225,000
4.20% Building Loan		10,824			10,927

Total debt		235,824			235,927
Less: current portion of long-term debt		(430	)		(425	)

Long-term debt	$	235,394		$	235,502

Current Portion of Long-Term Debt

As of March 31, 2018 (Successor), the current portion of long-term debt of $0.4 million represented principal payments due within one year on the 4.20% Building Loan (the “Building Loan”).

Revolving Credit Facility

On February 28, 2017, the Company entered into the Fifth Amended and Restated Credit Agreement with the lenders party thereto and Bank of America, N.A. (as amended from time to time, the “Amended Credit Agreement”), as administrative agent and issuing lender. The Amended Credit Agreement provides for a reserve-based revolving credit facility and matures on February 28, 2021.

The Company’s borrowing base under the Amended Credit Agreement was redetermined to $100 million on November 8, 2017. On March 31, 2018, the Company had no outstanding borrowings and $9.8 million of outstanding letters of credit, leaving $90.2 million of availability under the Amended Credit Agreement. 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. In connection with the pending Talos combination, the May 1, 2018 redetermination has been moved to June 1, 2018. Subject to certain exceptions, the Amended Credit Agreement is required to be guaranteed by all of the material domestic direct and indirect subsidiaries of the Company. As of March 31, 2018, the Amended Credit Agreement is guaranteed by Stone Energy Offshore, L.L.C. (“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 certain events of default, the lenders may take a number of actions, including declaring the entire amount then outstanding under the Amended Credit Agreement due and payable (in the event of certain insolvency-related events, the entire amount then outstanding under the Amended Credit Agreement will become automatically due and payable). The Amended Credit Agreement also requires maintenance of certain financial covenants, including (i) a consolidated funded debt to EBITDA ratio of not more than 2.50x for

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the test periods ending March 31, 2018, June 30, 2018, September 30, 2018 and December 31, 2018, respectively, 2.75x for the test period ending March 31, 2019, 3.00x for the test period ending June 30, 2019, 3.50x for the test periods ending September 30, 2019 and December 31, 2019, respectively, 3.00x for the test period ending March 31, 2020, 2.75x for the test periods ending June 30, 2020 and September 30, 2020, respectively, and 2.50x for the test periods ending December 31, 2020 and March 31, 2021, respectively, (ii) a consolidated interest coverage ratio of not less than 2.75 to 1.00, and (iii) a requirement to maintain minimum liquidity of at least 20% of the borrowing base. We were in compliance with all covenants under the Amended Credit Agreement as of March 31, 2018.

NOTE 9 – ASSET RETIREMENT OBLIGATIONS

The change in our asset retirement obligations during the three months ended March 31, 2018 (Successor) is set forth below (in thousands, inclusive of current portion):


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

Asset retirement obligations as of March 31, 2018 (Successor)	$	196,654

NOTE 10 – INCOME TAXES

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

As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of March 31, 2018 (Successor), our valuation allowance totaled $127.1 million. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities.

We had a current income tax receivable of $36.3 million at December 31, 2017 (Successor), which related to expected tax refunds from the carryback of net operating losses to previous tax years. In January 2018, we received $20.1 million of the tax refund and have a current income tax receivable of $16.2 million at March 31, 2018 (Successor).

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NOTE 11 – FAIR VALUE MEASUREMENTS

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

As of March 31, 2018 (Successor) and December 31, 2017 (Successor), we held certain financial assets that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. The income approach is used in this determination utilizing the third party’s proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar and put contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars and puts were the volatility impacts in the pricing model as it relates to the call portion of the collar and the floor of the put. For a more detailed description of our derivative instruments, see Note 7 – 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.

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


	Fair Value Measurements Successor as of March 31, 2018
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	4,964	$	4,964	$	—	$	—
Derivative contracts		417		—		—		417

Total	$	5,381	$	4,964	$	—	$	417


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

Total	$	17,711	$	—	$	15,330	$	2,381

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The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2017 (Successor) (in thousands).


	Fair Value Measurements Successor as of December 31, 2017
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	5,081	$	5,081	$	—	$	—
Derivative contracts		879		—		—		879

Total	$	5,960	$	5,081	$	—	$	879


	Fair Value Measurements Successor as of December 31, 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	$	12,054	$	—	$	10,110	$	1,944

Total	$	12,054	$	—	$	10,110	$	1,944

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 three months ended March 31, 2018 (Successor) (in thousands).


	Hedging Contracts, net
Balance as of January 1, 2018 (Successor)	$	(1,065	)
Total gains/(losses) (realized or unrealized):
Included in earnings		(1,579	)
Included in other comprehensive income		—
Purchases, sales, issuances and settlements		680
Transfers in and out of Level 3		—

Balance as of March 31, 2018 (Successor)	$	(1,964	)

The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at March 31, 2018	$	(4,702	)

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

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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.

NOTE 12 – COMBINATION TRANSACTION COSTS

In connection with the pending combination with Talos, we incurred approximately $3.4 million in transaction costs during the three months ended March 31, 2018 (Successor). These costs consist primarily of legal and financial advisor costs and are included in salaries, general and administrative (“SG&A”) expense on our statement of operations for the three months ended March 31, 2018 (Successor). Additionally, we have incurred approximately $0.2 million of direct costs for purposes of registering equity securities to effect the Talos combination. These direct costs were recorded as a reduction of additional paid-in-capital during 2017. See Note 1 – Financial Statement Presentation (Pending Combination with Talos) for more information on the pending combination.

NOTE 13 – REVENUE RECOGNITION

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

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

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

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Sales of oil, natural gas and NGLs are recognized when the product is delivered and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. To the extent actual quantities and values of oil, natural gas and NGL production for properties are not available for a given reporting period because of timing or information not received from the purchasers, the expected sales volumes and price are estimated and the result is recorded as purchaser accounts receivable (included in Accounts Receivable) in our balance sheet and as Oil, Natural Gas and NGL production revenue in our statement of operations. At March 31, 2018 (Successor), we recorded a purchaser accounts receivable of $31.2 million, consisting of $25.5 million of oil production revenue, $3.5 million of natural gas production revenue and $2.2 million of NGL production revenue. At December 31, 2017 (Successor), we recorded a purchaser accounts receivable of $32.8 million, consisting of $26.7 million of oil production revenue, $3.9 million of natural gas production revenue and $2.2 million of NGL production revenue. Revenue proceeds relating to third-party royalty owners not remitted by the end of a reporting period are recorded as Undistributed Oil and Gas Proceeds in our balance sheet.

NOTE 14 – PRODUCTION TAXES

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

NOTE 15 – COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Other Commitments and Contingencies

On March 21, 2016, we received notice letters from the Bureau of Ocean Energy Management (“BOEM”) stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at such time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. As of March 31, 2018, we have posted an aggregate of approximately $115 million in surety bonds in favor of BOEM, third-party bonds and letters of credit, all relating to our offshore abandonment obligations.

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

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

NOTE 16 – SUBSEQUENT EVENTS

On May 1, 2018, Stone completed the acquisition of a 100% working interest in the Ram Powell Unit, including six lease blocks in the Viosca Knoll Area, the Ram Powell tension leg platform (“TLP”), and related assets, from Shell Offshore Inc., Exxon Mobil Corporation, and Anadarko US Offshore LLC, for a purchase price of $34 million, with an effective date of October 1, 2017, and the posting of decommissioning surety bonds of $200 million. After considering the effects of customary purchase price adjustments from the effective date of the acquisition through closing, Stone received net cash of $29.4 million at closing.

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