Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________________________

FORM 10-Q

__________________________________________________________

(Mark One)



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

For the quarterly period ended March 31, 2018



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

For the transition period from to

Commission File Number: 1-12074

__________________________________________________________

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________



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

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

(337) 237-0410

(Registrant’s telephone number, including area code)

__________________________________________________________

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

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

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



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

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

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

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

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

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		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Condensed Consolidated Balance Sheet as of March 31, 2018 and December 31, 2017	1
	Condensed Consolidated Statement of Operations for the Three Months Ended March 31, 2018, the Period March 1, 2017 through March 31, 2017 and the Period January 1, 2017 through February 28, 2017	2
	Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2018, the Period March 1, 2017 through December 31, 2017 and the Period January 1, 2017 through February 28, 2017	3
	Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2018, the Period March 1, 2017 through March 31, 2017 and the Period January 1, 2017 through February 28, 2017	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 6.	Exhibits	35
	Signatures	37

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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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.

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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.

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STONE ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)



	Common Stock			Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			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.

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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.

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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 Annual Report on Form 10-K for the year ended December 31, 2017 (our “ 2017 Annual Report on Form 10-K”). The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations, contained in our 2017 Annual Report on Form 10-K, although, as described below, such prior financial statements will not be comparable to the interim financial statements due to the adoption of fresh start accounting on February 28, 2017. For additional information, see Note 3 – Fresh Start Accounting . The results of operations for the 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

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 11.0% 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.

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

On March 20, 2018, the Talos Issuers launched an offer to exchange (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

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

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

Reorganization and Emergence from Voluntary Reorganization Under Chapter 11 Proceedings

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

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

Use of Estimates

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

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.

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

Recently Issued Accounting Standards

In 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 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

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:


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


•	The Predecessor Company’s 7 ½% Senior Notes due 2022 (the “2022 Notes”) and 1 ¾% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) were cancelled and the holders of such notes received their pro rata share of (a) $100 million of cash, (b) 19.0 million shares of the New Common Stock, representing 95% of the New Common Stock and (c) $225 million of 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 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

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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.

NOTE 3 – FRESH START ACCOUNTING

Upon emergence from bankruptcy, the Company qualified for and adopted fresh start accounting in accordance with the provisions of ASC 852, “ Reorganizations ” as (i) the holders of existing voting shares of the Predecessor Company received less than 50% of the voting shares of the Successor Company and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the post-petition liabilities and allowed claims. See Note 2 – Reorganization for the terms of the Plan. The Company applied fresh start accounting as of February 28, 2017. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. As described in Note 1 – Financial Statement Presentation , the new entity is referred to as Successor or Successor Company, and includes the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

Reorganization Value

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

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

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% .

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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.

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 other amounts of the assets and liabilities as well as significant assumptions or inputs. The following table reflects the reorganization and application of ASC 852 on our consolidated balance sheet as of February 28, 2017 (in thousands):

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


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



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

(a) The closing of the sale of the Appalachia Properties occurred on February 27, 2017, but as emergence was contingent on such closing, the effects of the transaction are reflected as reorganization adjustments. See Note 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)	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.


2.	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 2 – Reorganization ).


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


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


5.	Reflects the write-off of $2.6 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.


6.	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.


7.	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.


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



1 ¾% Senior Convertible Notes due 2017	$	300,000
7 ½% Senior Notes due 2022	775,000
Accrued interest	35,182
Liabilities subject to compromise of the Predecessor Company	1,110,182
Cash payment to senior noteholders	(100,000		)
Issuance of 2022 Second Lien Notes to former holders of the senior notes	(225,000		)
Fair value of equity issued to unsecured creditors	(539,089		)
Fair value of warrants issued to unsecured creditors	(15,648		)
Gain on settlement of liabilities subject to compromise	$	230,445

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

10.

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

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

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

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.

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NOTE 4 – 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 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
	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

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. On February 28, 2017, upon emergence from bankruptcy, all outstanding stock options were cancelled.

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.

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. On February 28, 2017, upon emergence from bankruptcy, the 2017 Convertible Notes were cancelled. See Note 2 – Reorganization .

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.

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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

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

NOTE 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 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

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.

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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.

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

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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

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	)

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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		)

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

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.

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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 2.50 x for the test periods ending March 31, 2018, June 30, 2018, September 30, 2018 and December 31, 2018, respectively, 2.75 x for the test period ending March 31, 2019, 3.00 x for the test period ending June 30, 2019, 3.50 x for the test periods ending September 30, 2019 and December 31, 2019, respectively, 3.00 x for the test period ending March 31, 2020, 2.75 x for the test periods ending June 30, 2020 and September 30, 2020, respectively, and 2.50 x 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.

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

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NOTE 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.

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.

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NOTE 15 – 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.

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.

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

Forward-Looking Statements

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

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


•	expected results from risk-weighted drilling activities;


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


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


•	our outlook on oil and natural gas prices;


•	estimates of our oil and natural gas reserves;


•	any estimates of future earnings growth;


•	the impact of political and regulatory developments;


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


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


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


•	the outcome of restructuring efforts and asset sales;


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


•	any expected results or benefits associated with our acquisitions;


•	our access to capital and our anticipated liquidity;


•	estimates of future income taxes;


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


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


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

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


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


•	domestic and worldwide economic conditions, which may adversely affect the demand for and supply of oil and natural gas;


•	the availability of capital on economic terms to fund our operations, capital expenditures, acquisitions and other obligations;


•	our future level of indebtedness, liquidity and compliance with debt covenants;


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


•	the potential need to sell certain assets or raise additional capital;


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


•	declines in the value of our oil and gas properties resulting in a decrease in the borrowing base under our bank credit facility and impairments;


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


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


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


•	third-party interruption of sales to market;


•	inflation;


•	lack of availability and cost of goods and services;


•	market conditions relating to potential acquisition and divestiture transactions;

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


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


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


•	competition in the oil and gas industry;


•	our inability to retain and attract key personnel;


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


•	unsuccessful exploration and development drilling activities;


•	hurricanes and other weather conditions;


•	availability, cost and adequacy of insurance coverage;


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


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


•	other risks described in this Form 10-Q and our 2017 Annual Report on Form 10-K.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, Item 1A. Risk Factors , of this Form 10-Q and (2) Part I, Item 1A, of our 2017 Annual Report on Form 10-K. Should one or more of the risks or uncertainties described above, in our 2017 Annual Report on Form 10-K or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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

Critical Accounting Policies and Estimates

Our 2017 Annual Report on Form 10-K describes the accounting estimates that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments. Our most significant estimates are:


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


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


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


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


•	estimated fair value of derivative positions;


•	classification of unevaluated property costs;


•	capitalized general and administrative costs and interest;


•	estimates of fair value in business combinations;


•	estimates of reorganization value and enterprise value;


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


•	current and deferred income taxes; and


•	contingencies.

This Form 10-Q should be read together with the discussion contained in our 2017 Annual Report on Form 10-K regarding our critical accounting policies and estimates. There have been no material changes to our critical accounting policies from those described in our 2017 Annual Report on Form 10-K.

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

Other Factors Affecting Our Business and Financial Results

In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This Form 10-Q should be read in conjunction with the discussion in Part I, Item 1A, of our 2017 Annual Report on Form 10-K and in this Form 10-Q under Part II, Item 1A. Risk Factors , regarding our known material risk factors.

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Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf of Mexico (“GOM”) Basin since our incorporation in 1993 and have established technical and operational expertise in this area. We leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific plays of the GOM deep water and Gulf Coast deep gas.

As discussed in Part I, Item 1. Financial Statements – Note 3 – Fresh Start Accounting , upon emergence from bankruptcy, the Company adopted fresh start accounting in accordance with the provisions of ASC 852, “ Reorganizations ”, which resulted in the Company becoming a new entity for financial reporting purposes on the Effective Date. Fresh start accounting required the Company to present its assets, liabilities and equity as if it were a new entity upon emergence from bankruptcy, with no beginning retained earnings or deficit as of the fresh start reporting date. As a result of the adoption of fresh start accounting, the Company’s unaudited condensed consolidated financial statements subsequent to February 28, 2017 will not be comparable to its financial statements prior to that date. References to Successor or Successor Company relate to the financial position and results of operations of the reorganized Company subsequent to February 28, 2017. References to Predecessor or Predecessor Company relate to the financial position and results of operations of the Company prior to, and including, February 28, 2017.

Pending Combination with Talos

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

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

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

Reorganization and Emergence from Voluntary Chapter 11 Proceedings

On December 14, 2016, we filed voluntary petitions seeking relief under the provisions of Chapter 11 of the United States Bankruptcy Code to pursue a prepackaged plan of reorganization to address our liquidity and capital structure. On February 28, 2017, the Plan became effective and we emerged from bankruptcy. In connection with our reorganization, we sold our Appalachia Properties on February 27, 2017 for net cash consideration of approximately $522.5 million. Upon closing of the sale on February 27, 2017, we no longer have operations or assets in Appalachia. A portion of the consideration received from the sale of the Appalachia Properties was used to fund the Company’s cash payment obligations under the Plan.

Upon emergence from bankruptcy, pursuant to the terms of the Plan, the Predecessor Company’s 2022 Notes and 2017 Convertible Notes were cancelled and the holders of such notes received their pro rata share of $100 million of cash, 19.0 million shares of the New Common Stock (representing 95% of the New Common Stock) and $225 million of 2022 Second Lien Notes. The Predecessor Company’s

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Pre-Emergence Credit Agreement was amended and restated as the Amended Credit Agreement. The Predecessor Company’s common stockholders received their pro rata share of 1.0 million shares of the New Common Stock (representing 5% of the New Common Stock) and warrants to purchase approximately 3.5 million shares of New Common Stock. The warrants have an exercise price of $42.04 per share and a term of four years, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. See Liquidity and Capital Resources below for additional information on the Successor Company’s debt instruments.

Operational Update

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 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. Production for the Ram Powell field averaged approximately 6,100 Boe per day during 2017. The Ram Powell TLP is located in 3,200 feet of water in Viosca Knoll Area, Block 956 and is capable of producing 60,000 barrels of oil per day and 200 million cubic feet of gas per day, which could allow for potential processing of additional third party production.

The Derbio exploration well (Mississippi Canyon Block 72 #3 well) reached total depth in April 2018 and encountered reservoir-quality sands in the targeted objective that did not contain commercial saturations of hydrocarbons. The partners are now evaluating the possible development of the Rampart Deep well as a single-well tieback. Stone has a 40% working interest in the Derbio well.

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

Known Trends and Uncertainties

Commodity Derivative Income (Expense) – We account for derivative instruments on a mark-to-market basis with changes in fair value recognized currently in earnings through derivative income (expense) in the statement of operations. As a result of these mark-to-market adjustments, we will likely experience volatility in earnings from time to time due to commodity price volatility. See Results of Operations below for more information.

BOEM Financial Assurance Requirements – BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we and many other operators have been able to obtain an exemption from most bonding obligations based on financial net worth.

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

In July 2016, BOEM issued a 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.

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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. Compliance with the NTL, or any other new rules, regulations, or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, limit our activities in certain areas, cause us to incur penalties or fines or to shut-in production at one or more of our facilities, or result in the suspension or cancellation of leases.

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 conjunction with the acquisition of the Ram Powell field on May 1, 2018 (see Part I, Item 1. Financial Statements – Note 16 – Subsequent Events) , we have posted an additional $200 million in surety bonds. The bonds represent guarantees by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements. There is no assurance that our current tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. A revised tailored plan may require incremental financial assurance or bonding for non-sole liability properties, dependent on adjustments following ongoing discussions with BOEM and BSEE and any modifications to the proposed NTL.

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

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

Liquidity and Capital Resources

Overview

As of May 7, 2018 , we had approximately $295 million of cash on hand and $90.2 million of availability under the Amended Credit Agreement, and $235.7 million in total debt outstanding, including $225 million of 2022 Second Lien Notes and $10.7 million outstanding under the Building Loan.

In January 2018, the Board authorized a 2018 capital expenditure budget of up to $212 million, which excludes acquisitions and capitalized SG&A and interest, and does not give effect to the potential Talos combination. The budget is spread across Stone's major areas of investment, with approximately 36% allocated to exploration, 27% to development, and 37% to plugging and abandonment expenditures. The allocation of capital across the various areas is subject to change based on several factors, including permitting times, rig availability, non-operator decisions, farm-in opportunities, and commodity pricing. Based on our current outlook of commodity prices and our estimated production for 2018, we expect that cash flows from operating activities, cash on hand and availability under the Amended Credit Agreement will be adequate to meet the current 2018 operating and capital expenditure needs of the Company.

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 conjunction with the acquisition of the Ram Powell field on May 1, 2018 ( see Part I, Item 1. Financial Statements – Note 16 – Subsequent Events ), we have posted an additional $200 million in surety bonds. Although the surety companies have not historically required collateral from us to back our surety bonds, we have provided some cash collateral on an immaterial portion of our existing surety bonds and may be required to provide additional cash collateral on existing and/or new surety bonds required by BOEM to satisfy financial assurance requirements. See Known Trends and Uncertainties above.

Indebtedness

Bank Credit Facility – On February 28, 2017, we entered into the Amended Credit Agreement, which provides for a reserve-based revolving credit facility and matures on February 28, 2021. The borrowing base under the Amended Credit Agreement was redetermined to $100 million on November 8, 2017. At May 7, 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 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.

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

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

Cash Flow and Working Capital

Net cash provided by (used in) operating activities totaled $32.5 million during the three months ended March 31, 2018 (Successor) compared to $10.6 million during the period of March 1, 2017 through March 31, 2017 (Successor) and ($5.9) million during the period of January 1, 2017 through February 28, 2017 (Predecessor). Operating cash flows were positively impacted during the three months ended March 31, 2018 (Successor) by decreases in TP&G expenses and incentive compensation expenses, the receipt of income and severance tax refunds and an increase in the average realized price received for our oil production. Decreases in natural gas and NGL production volumes, and the cash settlements of our derivative contracts resulted in decreases in operating cash flows for the three months ended March 31, 2018 (Successor). Included in operating cash flows for the period of January 1, 2017 through February 28, 2017 (Predecessor) is the payment to Tug Hill of approximately $11.5 million for a break-up fee and expense reimbursements upon termination of the Tug Hill purchase and sale agreement. See Results of Operations below for additional information relative to commodity prices, production and operating expense variances.

Net cash used in investing activities totaled $ 36.8 million during the three months ended March 31, 2018 (Successor), which primarily represents our investment in oil and gas properties. Net cash provided by investing activities totaled $5.2 million during the period of March 1, 2017 through March 31, 2017 (Successor) and $ 496.6 million during the period of January 1, 2017 through February 28, 2017 (Predecessor), which primarily represents net proceeds from the sale of the Appalachia Properties, partially offset by our investment in oil and gas properties.

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

We had working capital at March 31, 2018 (Successor) of $ 223.8 million .

Capital Expenditures

During the three months ended March 31, 2018 , net additions to oil and gas properties of $16.3 million included $1.6 million of capitalized SG&A expenses and $1.4 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities. These additions to oil and gas property costs exclude approximately $20.7 million of plugging and abandonment expenditures which are recorded as a reduction of asset retirement obligations.

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Contractual Obligations and Other Commitments

We have various contractual obligations and other commitments in the normal course of operations. For further information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations and Other Commitments” in our 2017 Annual Report on Form 10-K. There have been no material changes to this disclosure during the three months ended March 31, 2018 .

Results of Operations

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



	Successor				Predecessor
	Three Months Ended March 31, 2018		Period from March 1, 2017 through March 31, 2017		Period from January 1, 2017 through February 28, 2017
Production:
Oil (MBbls)	1,126		410		908
Natural gas (MMcf)	2,015		818		5,037
NGLs (MBbls)	108		31		408
Oil, natural gas and NGLs (MBoe)	1,570		577		2,156
Revenue data (in thousands):
Oil revenue	$	73,261	$	20,027	$	45,837
Natural gas revenue	4,900		2,210		13,476
NGLs revenue	3,188		777		8,706
Total oil, natural gas and NGL revenue	$	81,349	$	23,014	$	68,019
Average prices:
Oil (per Bbl)	$	65.06	$	48.85	$	50.48
Natural gas (per Mcf)	$	2.43	$	2.70	$	2.68
NGLs (per Bbl)	$	29.52	$	25.06	$	21.34
Oil, natural gas and NGLs (per Boe)	$	51.81	$	39.89	$	31.55
Expenses (in thousands):
Lease operating expenses	$	14,380	$	4,740	$	8,820
Transportation, processing and gathering expenses	$	783	$	144	$	6,933
Salaries, general and administrative expenses (1)	$	12,556	$	3,322	$	9,629
DD&A expense on oil and gas properties	$	20,601	$	15,525	$	36,751
Expenses (per Boe):
Lease operating expenses	$	9.16	$	8.21	$	4.09
Transportation, processing and gathering expenses	$	0.50	$	0.25	$	3.22
Salaries, general and administrative expenses (1)	$	8.00	$	5.76	$	4.47
DD&A expense on oil and gas properties	$	13.12	$	26.89	$	17.05

(1) Excludes incentive compensation expense.

Net Income/Loss. During the three months ended March 31, 2018 (Successor), we reported net income of $18.3 million ( $0.91 per share). During the period of March 1, 2017 through March 31, 2017 (Successor), we reported a net loss of $259.6 million ( $12.98 per share) and during the period of January 1, 2017 through February 28, 2017 (Predecessor), we reported net income of $630.3 million ( $110.99 per share).

Write-down of oil and gas properties – We follow the full cost method of accounting for oil and gas properties. During the period of March 1, 2017 through March 31, 2017 (Successor), we recognized a ceiling test write-down of our U.S. oil and gas properties totaling $256.4 million . The write-down did not impact our cash flows from operating activities but did reduce net income and stockholders’ equity. The March 31, 2017 write-down of oil and gas properties was primarily due to differences between the trailing twelve-month

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average pricing assumption used in calculating the ceiling test and the forward prices used in fresh start accounting to estimate the fair value of our oil and gas properties on the fresh start reporting date of February 28, 2017.

Sale of Appalachia Properties – During the period of January 1, 2017 through February 28, 2017 (Predecessor), we recognized a $213.5 million gain on the sale of the Appalachia Properties, representing the excess of the proceeds from the sale over the carrying amount attributed to the oil and gas properties sold, adjusted for transaction costs and other items. See Part I, Item 1. Financial Statements – Note 5 – Divestiture for additional details.

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

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

Production. During the three months ended March 31, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), total production volumes were 1,570 MBoe, 577 MBoe and 2,156 MBoe, respectively. Oil production during the three months ended March 31, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor) totaled 1,126 MBbls, 410 MBbls and 908 MBls, respectively. Natural gas production totaled 2.0 Bcf, 0.8 Bcf and 5.0 Bcf during the three months ended March 31, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), respectively. NGL production during the three months ended March 31, 2018 (Successor), the period of March 1, 2017 through March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor), totaled approximately 108 MBls, 31 MBbls and 408 MBbls, respectively.

On February 27, 2017, we completed the sale of the Appalachia Properties to EQT. For the period of January 1, 2017 through February 27, 2017, total production volumes attributable to the Appalachia Properties were 965 MBoe, comprised of 3.5 Bcf of natural gas, 57 MBbls of oil and 330 MBbls of NGLs.

Prices . Prices realized during the three months ended March 31, 2018 (Successor) averaged $65.06 per Bbl of oil, $2.43 per Mcf of natural gas and $29.52 per Bbl of NGLs. Prices realized during the period of March 1, 2017 through March 31, 2017 (Successor) averaged $48.85 per Bbl of oil, $2.70 per Mcf of natural gas and $25.06 per Bbl of NGLs. Prices realized during the period of January 1, 2017 through February 28, 2017 (Predecessor) averaged $50.48 per Bbl of oil, $2.68 per Mcf of natural gas and $21.34 per Bbl of NGLs.

Revenue. Oil, natural gas and NGL revenue was $81.3 million , $23.0 million and $68.0 million 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), respectively. The decrease in total revenue in 2018 was primarily due to a decrease in oil, natural gas and NGL production volumes partially offset by an increase in average realized oil and NGL prices. For the period of January 1, 2017 through February 27, 2017, total oil, natural gas and NGL revenues attributable to the Appalachia Properties were $18.6 million.

Derivative Income/Expense. The net changes in the mark-to-market valuations and the monthly settlements of our derivative contracts are recorded in earnings in derivative income (expense). See Known Trends and Uncertainties . Net derivative expense for the three months ended March 31, 2018 (Successor) totaled $9.5 million , comprised of $3.4 million of expense from cash settlements and $6.1 million of non-cash expense resulting from changes in the fair value of derivative instruments. Net derivative income for the period of March 1, 2017 through March 31, 2017 (Successor) totaled $2.6 million , comprised of $2.5 million of non-cash income resulting from changes in the fair value of derivative instruments, $0.2 million of income from cash settlements and $0.1 million of non-cash expense for the amortization of the cost of the puts. Net derivative expense for the period of January 1, 2017 through February 28, 2017 (Predecessor) totaled $1.8 million , comprised of $1.7 million of non-cash expense resulting from changes in the fair value of derivative instruments and $0.1 million of non-cash expense for the amortization of the puts.

Expenses. Lease operating expenses 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 $14.4 million , $4.7 million and $8.8 million , respectively, or $9.16 per Boe, $8.21 per Boe and $4.09 per Boe, respectively. Lease operating expenses in 2018 included charges for major maintenance projects. For the period of January 1, 2017 through February 27, 2017, lease operating expenses attributable to the Appalachia Properties totaled $2.3 million. For the three months ended March 31, 2018, the higher per unit lease operating expense was the result of the sale of the lower-cost Appalachia Properties combined with lower production volumes from our GOM properties.

Transportation, processing and gathering (“TP&G”) expenses 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 $0.8 million , $0.1 million and $6.9 million , respectively, or $0.50 per Boe, $0.25 per Boe and $3.22 per Boe, respectively. TP&G expenses

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for the Predecessor period primarily related to the Appalachia Properties, which were sold on February 27, 2017. For the period of January 1, 2017 through February 27, 2017, TP&G expenses attributable to the Appalachia Properties totaled $6.8 million.

DD&A expense on oil and gas properties for the three months ended 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 $20.6 million , $15.5 million and $36.8 million , respectively, or $13.12 per Boe, $26.89 per Boe and $17.05 per Boe, respectively. The decrease in DD&A for the three months ended March 31, 2018 was primarily due to the ceiling test write-down of our oil and gas properties at March 31, 2017, which resulted from 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.

SG&A expenses (exclusive of incentive compensation) for the three months ended March 31, 2018 (Successor), the period of March 1, 2017 and March 31, 2017 (Successor) and the period of January 1, 2017 through February 28, 2017 (Predecessor) were $12.6 million , $3.3 million and $9.6 million , respectively, or $8.00 per Boe, $5.76 per Boe and $4.47 per Boe, respectively. The decrease in SG&A expenses that resulted from staff reductions made in 2017 was offset by costs associated with the pending Talos combination during the three months ended March 31, 2018 (Successor). For the three months ended March 31, 2018 (Successor), SG&A expenses increased on a unit of production basis as a result of lower production volumes for that period.

Interest expense totaled $3.5 million (net of $1.4 million of capitalized interest) and $1.2 million (net of $0.4 million of capitalized interest) for the three months ended March 31, 2018 (Successor) and the period of March 1, 2017 through March 31, 2017 (Successor), respectively. Interest expense for the 2017 and 2018 periods included interest associated with the 2022 Second Lien Notes issued on February 28, 2017.

For the period of January 1, 2017 through February 28, 2017 (Predecessor) we recorded an income tax provision of $3.6 million . As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined in the third quarter of 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. We also established a valuation allowance against a portion of our deferred tax assets upon emergence from bankruptcy as part of fresh start accounting, and the subsequent change in the valuation allowance was recorded as an adjustment to the income tax provision. See Part I, Item 1. Financial Statements – Note 10 – Income Taxes .

Off-Balance Sheet Arrangements

None.

Recently Adopted Accounting Standards

In May 2014, the FASB issued ASU 2014-09, “ Revenue from Contracts with Customers (Topic 606)” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. 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 did result in increased disclosures related to revenue recognition policies and disaggregation of revenues. See Part I, Item 1. Financial Statements – Note 13 – Revenue Recognition .

Recently Issued Accounting Standards

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Defined Terms

Oil, condensate and NGLs are stated in barrels (“Bbls”) or thousand barrels (“MBbls”). Natural gas is stated in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). A barrel of oil equivalent (“Boe”) is determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. MMBoe and MBoe represent one million and one thousand barrels of oil equivalent, respectively. MMBtu represents one million British Thermal Units. An active property is an oil and gas property with existing production. A primary term lease is an oil and gas property with no existing production, in which we have a specific time frame to establish production without losing the rights to explore the property. Liquidity is defined as the ability to obtain cash quickly either through the conversion of assets or incurrence of liabilities.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. For the three months ended March 31, 2018 , a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $5.7 million impact on our cash flows from operating activities. In order to manage our exposure to oil and natural gas price declines, we enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.

Our hedging policy currently provides that not more than 60% of our estimated production quantities can be hedged for any given month without the consent of the Board. Additionally, a minimum of 25% of each month’s production will not be committed to any hedge contract regardless of the price available. We believe that our outstanding hedging positions as of May 7, 2018 have hedged approximately 46% of our estimated 2018 production from estimated proved producing reserves and 35% of our estimated 2019 production from estimated proved producing reserves. We continue to monitor the marketplace for additional hedges we deem acceptable. See Part I, Item 1. Financial Statements – Note 7 – Derivative Instruments and Hedging Activities , of this Form 10-Q for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Since the filing of our 2017 Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to commodity prices.

Interest Rate Risk

We had total debt outstanding of $235.8 million at March 31, 2018 , all of which bears interest at fixed rates. The $235.8 million of fixed-rate debt is comprised of $225 million of the 2022 Second Lien Notes and $10.8 million of the Building Loan.

Our Amended Credit Agreement is subject to an adjustable interest rate. See Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources of this Form 10-Q. At May 7, 2018 , we had no outstanding borrowings under our Amended Credit Agreement. If we borrow funds under our Amended Credit Agreement, we may be subject to increased sensitivity to interest rate movements. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates.

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ITEM 4. CONTROLS AND PRODECURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2018 at the reasonable assurance level.

Changes in Internal Controls Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended March 31, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in two of the three Jefferson Parish Coastal Zone Management lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed.

In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The Plaquemines Parish lawsuit has been stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone.

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

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

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

ITEM 1A. RISK FACTORS

There have been no material changes with respect to Stone’s risk factors previously reported in Part I, Item 1A, of our 2017 Annual Report on Form 10-K.

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

Shares of our common stock are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the granting of stock awards and the lapsing of forfeiture restrictions of restricted stock. These withheld shares are not issued or considered common stock repurchases under any authorized share repurchase program. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the three months ended March 31, 2018 .



Period		Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
January 1 - January 31, 2018	(Successor)	411	$	35.77	—
February 1 - February 28, 2018	(Successor)	—	—		—
March 1 - March 31, 2018	(Successor)	—	—		—
Total		411	35.77			$	—


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

ITEM 6. EXHIBITS



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

______________________________________________

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

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SIGNATURES

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



		STONE ENERGY CORPORATION

Date:	May 7, 2018	By:	/s/ Kenneth H. Beer
			Kenneth H. Beer
			Executive Vice President and Chief Financial Officer
			(On behalf of the Registrant and as
			Principal Financial Officer)

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