Stone Energy 10K 2016 Annual report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

[ ] 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)

Registrant’s telephone number, including area code: (337) 237-0410

Securities registered pursuant to Section 12(b) of the Act:



Title of each class			Name of each exchange on which registered
Common Stock, Par Value $.01 Per Share			New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. [ ] Yes [X] No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. [ ] Yes [X] No

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. [X] Yes [ ] 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). [X] Yes [ ] No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

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



Large accelerated filer [ ]	Accelerated filer [X]	Non-accelerated filer [ ] (Do not check if a smaller reporting company)	Smaller reporting company [ ]

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

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $66.3 million as of June 30, 2016 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

As of February 23, 2017, the registrant had outstanding 5,679,765 shares of Common Stock, par value $.01 per share.

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TABLE OF CONTENTS



		Page No.
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures	35

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 8.	Financial Statements and Supplementary Data	60
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	60
Item 9A.	Controls and Procedures	60
Item 9B.	Other Information	62

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	62
Item 11.	Executive Compensation	67
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	95
Item 13.	Certain Relationships and Related Transactions, and Director Independence	96
Item 14.	Principal Accountant Fees and Services	97

PART IV

Item 15.	Exhibits and Financial Statement Schedules	98
	Index to Financial Statements	F-1
	Glossary of Certain Industry Terms	G-1

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PART I

This section highlights information that is discussed in more detail in the remainder of the document. Throughout this document, we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section beginning on page 10 of this document for an explanation of these types of statements. We use the terms “Stone,” “Stone Energy,” “Company,” “we,” “us” and “our” to refer to Stone Energy Corporation and its consolidated subsidiaries. Certain terms relating to the oil and gas industry are defined in “Glossary of Certain Industry Terms,” which begins on page G-1 of this Annual Report on Form 10-K (this “Form 10-K”).

ITEM 1. BUSINESS

The Company

Stone Energy is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf of Mexico (the "GOM") Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. As of December 31, 2016, our estimated proved oil and natural gas reserves were approximately 53 MMBoe or 321 Bcfe. In connection with our restructuring efforts, we entered into a purchase and sale agreement to sell all of our Appalachia Properties (as defined in Reorganization and Chapter 11 Proceedings – Purchase and Sale Agreement below). We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions, after which we will no longer have operations or assets in Appalachia.

We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia.

Business Strategy

Our long-term strategy is to grow net asset value through acquiring, discovering, developing and operating a focused set of margin-advantaged properties while appropriately managing financial, exploration and operational risk. During the second half of 2014, commodity prices began a substantial decline, which continued throughout 2015 and 2016. In response to that decline and the uncertainty regarding future commodity prices, we adjusted our near-term strategy to focus on maintaining maximum liquidity, which included reductions in capital expenditures in 2016 and the shut-in of our Mary field in Appalachia from September 2015 until late June 2016. In March 2016, we retained financial and legal advisors to assist the Company in analyzing and considering financial, transactional and strategic alternatives.

Overview

In response to the significant decline in commodity prices, we focused on managing our balance sheet during 2016 to preserve liquidity during this extended low commodity price environment by taking certain steps, including reductions in capital expenditures and the termination and renegotiation of various contracts, reductions in workforce and reductions in discretionary expenditures. Additionally, in March 2016, we retained financial and legal advisors to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We engaged in negotiations with financial advisors for the holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes and with our banks regarding an amendment to our bank credit facility.

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deficiency. In June 2016, however, we entered into Amendment No. 3 (the "June Amendment") to our bank credit facility which, among other things, resulted in an increase of our borrowing base from $300 million to $360 million and relaxed certain financial covenants through December 31, 2016. In addition, the June Amendment required that we maintain minimum liquidity (as defined in the June Amendment) of $125.0 million through January 15, 2017, imposed limitations on capital expenditures from June to December 2016 and provided for anti-hoarding cash provisions for amounts in excess of $50.0 million beginning after December 10, 2016. Upon execution of the June Amendment, we repaid the balance of our borrowing base deficiency, resulting in approximately $360 million outstanding under the credit facility at that time. In December 2016, we reached agreements with the banks to extend the effective date of the anti-hoarding cash provisions to December 15, 2016.

In June 2016, we terminated our deep water drilling rig contract with Ensco for total consideration of $20 million. Additionally, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, whereby we elected to resume production at the Mary field, which had been shut-in since September 2015. In August 2016, we paid $7.5 million for the early terminations of an Appalachian drilling rig contract and a contract with an offshore vessel provider.

As of September 30, 2016, we were in compliance with all covenants under the bank credit facility and the indentures governing our notes, however, we anticipated that the minimum liquidity requirement and other restrictions under the June Amendment would prevent us from being able to meet our interest payment obligation on the 2022 Notes in the fourth quarter of 2016 as well as the subsequent maturity of our 2017 Convertible Notes on March 1, 2017. As a result of these conditions, continued decreases in commodity prices and the significant level of our indebtedness, we continued to work with our financial and legal advisors throughout 2016 to structure a plan of reorganization to improve our financial position and liquidity and allow for growth and long-term success. On December 14, 2016, we filed for bankruptcy.

Reorganization and Chapter 11 Proceedings

On December 14, 2016, the Company and its subsidiaries Stone Energy Offshore, L.L.C. ("Stone Offshore") and Stone Energy Holding, L.L.C. (together with the Company, the "Debtors") filed voluntary petitions for reorganization (the "Bankruptcy Petitions") in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the "Bankruptcy Court") seeking relief under the provisions of Chapter 11 of Title 11 ("Chapter 11") of the United States Bankruptcy Code (the "Bankruptcy Code"). On February 15, 2017, the Bankruptcy Court entered an order (the "Confirmation Order"), confirming the Company's plan of reorganization (the "Plan"), as modified by the Confirmation Order. We expect the Plan to become effective on February 28, 2017, at which point the Debtors would emerge from bankruptcy, however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all.

During the bankruptcy proceedings, the Debtors are operating as "debtors-in-possession" in accordance with applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by the Debtors, allowing the Company to operate its business in the ordinary course throughout the bankruptcy process. The first day motions included, among other things, a cash collateral motion, a motion maintaining the Company's existing cash management system and motions making various vendor payments, wage payments and tax payments in the ordinary course of business. Subject to certain exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Debtors or their property to recover, collect or secure a pre-petition claim. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements.

Restructuring Support Agreement. Prior to filing the Bankruptcy Petitions, on October 20, 2016, the Debtors entered into a restructuring support agreement (the "Original RSA") with certain holders of the 2017 Convertible Notes and the 2022 Notes (collectively, the "Notes" and the holders thereof, the "Noteholders") to support a restructuring on the terms of the Plan. On November 17, 2016, the Debtors commenced a solicitation to seek acceptance by a majority of those voting in each voting class of claims of the Company’s creditors under the Plan, including the lenders (the "Banks") under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the "Credit Facility"), and the Noteholders. On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into an Amended and Restated Restructuring Support Agreement (the "A&R RSA") that amended, superseded and restated in its entirety the Original RSA. In connection with entry into the A&R RSA and the commencement of the bankruptcy cases, the Debtors amended the Plan. The solicitation period ended on December 16, 2016 and (i) of the 94.24% of Noteholders in aggregate outstanding principal amount that voted, 99.95% voted in favor of the Plan and .05% voted to reject the Plan, and (ii) 100% of the Banks voted to accept the Plan.

Additionally, on December 16, 2016, an ad hoc group of certain of the Company's stockholders (the "Stockholder Ad Hoc Group") filed a motion (the "Equity Committee Motion") to appoint an official committee of equity security holders in connection with the Debtors' Chapter 11 proceedings. On December 21, 2016, the Company reached a settlement agreement with the Stockholder Ad Hoc Group (the "Settlement") and on December 28, 2016, the Plan was amended.

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Pursuant to the terms of the Plan, as amended, to be consistent with the terms of the A&R RSA and the term sheet annexed to the A&R RSA (the "Term Sheet") and as amended pursuant to the Settlement, the Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of new 7.5% second lien notes due 2022 (the "Second Lien Notes"). The Banks will receive their respective pro rata share of commitments and obligations under an amended credit agreement (the "Amended Credit Facility") on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA (as defined below). Existing common stockholders of Stone will receive their pro rata share of 5% of the common stock in reorganized Stone and warrants for ownership of up to 15% of reorganized Stone's common equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the new warrants, which may be exercised any time prior to the fourth anniversary of the Plan's effective date, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company. All claims of creditors with unsecured claims other than claims by the Noteholders, including vendors, shall be unaltered and will be paid in full in the ordinary course of business to the extent such claims are undisputed. Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan. Assuming implementation of the Plan, Stone expects that it will eliminate approximately $1.2 billion in principal amount of outstanding debt.

Purchase and Sale Agreement. The A&R RSA contained certain covenants on the part of the Company and the Noteholders and Banks who are signatories to the A&R RSA, including that such Noteholders and Banks would support the Company's sale of Stone's producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the "Appalachia Properties") to TH Exploration III, LLC, an affiliate of Tug Hill, Inc. ("Tug Hill"), pursuant to the terms of a Purchase and Sale Agreement dated October 20, 2016, as amended on December 9, 2016 (the "Tug Hill PSA"), and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the A&R RSA. The consummation of the Plan is subject to customary conditions and other requirements, as well as the sale by Stone of the Appalachia Properties, for a purchase price of at least $350 million and approval of the Bankruptcy Court. Pursuant to the terms of the Tug Hill PSA, Stone agreed to sell the Appalachia Properties to Tug Hill for $360 million in cash, subject to customary purchase price adjustments.

Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017, two additional bidders were allowed to participate in competitive bidding on the Appalachia Properties. On January 18, 2017, the Bankruptcy Court approved certain bidding procedures (the "Bidding Procedures") in connection with the sale of the Appalachia Properties. In accordance with the Bidding Procedures, Stone conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT Corporation, through its wholly-owned subsidiary EQT Production Company ("EQT"), with a final purchase price of $527 million in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court, with an upward adjustment to the purchase price of up to $16 million in an amount equal to certain downward adjustments, as the prevailing bid.

For additional information on the bankruptcy proceedings, the A&R RSA, the Tug Hill PSA and the EQT PSA, see Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Operational Overview

Gulf of Mexico Basin

Our GOM Basin properties accounted for approximately 66% of our estimated proved oil and natural gas reserves at December 31, 2016 on a volume equivalent basis. We have properties in the deep water of the GOM, as well as limited exposure to GOM conventional shelf and deep gas properties. In 2014, we sold a majority of our GOM conventional shelf properties.

Gulf of Mexico — Deep Water. We believe that the deep water of the GOM is an attractive area to acquire, explore, develop and operate with high-potential investment opportunities. We have made significant investments in seismic data and leasehold interests and have assembled a technical team with prior geological, geophysical, engineering and operational experience in the deep water arena to evaluate potential exploration, development and acquisition opportunities. Since 2006, we have made two

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significant acquisitions that included two deep water platforms, producing reserves and numerous leases. We have a portfolio of deep water projects ranging from lower risk development projects incorporating existing facilities to higher risk exploration prospects that would require a new production facility. We have utilized subsea tie-backs in the deep water on new drill wells, which require less capital and time than new deep water facilities. We have higher risk exploration prospects that could expose the company to significant reserves if successful. Projects in the deep water typically require substantially more time, planning, manpower and capital than an onshore project. Our deep water properties accounted for approximately 56% of our estimated proved oil and natural gas reserves at December 31, 2016 on a volume equivalent basis.

Gulf Coast — Conventional Shelf and Deep Gas. We have historically focused on the GOM conventional shelf, but after the sale of a majority of our GOM conventional shelf properties in 2014, we have significantly reduced our exposure in this area to primarily two remaining fields, which provide production and cash flow. There are limited exploitation and exploration projects for us on our GOM conventional shelf properties. The Gulf Coast deep gas play (prospects below 15,000 feet) provides us with higher potential exploration opportunities with existing infrastructure nearby, which shortens the lead time to production. Our conventional shelf and deep gas properties accounted for approximately 10% of our estimated proved oil and natural gas reserves at December 31, 2016 on a volume equivalent basis.

Appalachia

In response to low commodity prices and high midstream costs in the area, we shut in our Mary field from September 2015 until late June 2016 and suspended completion operations on 25 drilled wells in Appalachia until commodity prices and margin improvements could be realized. In late June 2016, we entered into an interim Appalachian midstream contract that provided near-term relief by permitting us to resume profitable production and positive cash flow at the Mary field.

In connection with our restructuring efforts, we determined that a sale of the Appalachia Properties would be a beneficial way to maximize value for all stakeholders. On February 9, 2017, we entered into the EQT PSA, and expect to close on the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions. At December 31, 2016, the Appalachia Properties accounted for approximately 34% of our estimated proved oil and natural gas reserves on a volume equivalent basis. Upon closing, we will no longer have operations or assets in Appalachia. See Reorganization and Chapter 11 Proceedings – Purchase and Sale Agreement above.

Business Development

In prior years, the business development effort was focused on providing Stone with exposure to new or unproven plays that could add significant value to the Company if successful. Given the uncertainty regarding future commodity prices, we have only minimal capital allocated for onshore exploration projects or new venture opportunities.

Oil and Gas Marketing

Our oil and natural gas production is sold at current market prices under short-term contracts. Phillips 66 Company and Shell Trading (US) Company accounted for approximately 68% and 10%, respectively, of our oil and natural gas revenue generated during the year ended December 31, 2016. We do not believe that the loss of any of our major purchasers would result in a material adverse effect on our ability to market future oil and natural gas production. From time to time, we may enter into transactions that hedge the price of oil and natural gas. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.

Competition and Markets

Competition in the GOM Basin and other onshore plays is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete. See Item 1A. Risk Factors – Competition within our industry may adversely affect our operations.

The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control, including, but not limited to, the amount of domestic production and imports of foreign oil and exports of liquefied natural gas, the marketing of competitive fuels, the proximity and capacity of oil and natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of allowable rates of production, taxation and the conduct of drilling operations and federal regulation of oil and natural gas. All of these factors, together with

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economic factors in the marketing arena, generally may affect the supply of and/or demand for oil and natural gas and thus the prices available for sales of oil and natural gas.

Regulation

Our oil and gas operations are subject to various U.S. federal, state and local laws and regulations.

Various aspects of our oil and natural gas operations are regulated by certain agencies of the federal government for our operations on federal leases. The jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area and the unitization or pooling of oil and natural gas properties. In this regard, some agencies can order the pooling or integration of tracts to facilitate exploration while others rely on voluntary pooling of lands and leases. In addition, certain conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Outer Continental Shelf Regulation. Our operations on federal oil and gas leases in the GOM are subject to regulation by the Bureau of Safety and Environmental Enforcement ("BSEE") and the Bureau of Ocean Energy Management ("BOEM"). These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act. These laws and regulations are subject to change, and many new requirements were imposed by the BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (the "EPA"), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Outer Continental Shelf ("OCS"), calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. These rules are frequently subject to change. For example, in April 2016, BSEE issued its final well control regulations, effective July 2016, though some requirements of the rule have delayed compliance deadlines. The final rule addresses the full range of systems and equipment associated with well control operations, focusing on requirements for blowout preventers ("BOPs"), well design, well control casing, cementing, real-time monitoring and subsea containment. Key features of the well control regulations include requirements for BOPs, double shear rams, third-party reviews of equipment, real-time monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing, cementing and subsea containment. Separately, BOEM proposed new rules in April 2016 that would update existing air emissions requirements relating to offshore oil and natural gas activity on federal OCS waters including in the Central Gulf of Mexico. BOEM regulates these air emissions in connection with its review of exploration and development plans, and right-of-use and right-of-way applications. The proposed rule would bolster existing air emission reporting requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. Compliance with new and future regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, under certain circumstances, the BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect our financial condition and operations.

Additionally, on July 14, 2016, BOEM issued a new Notice to Lessees ("NTL"), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurance by offshore lessees. The NTL discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and, consistent with those procedures, BOEM has tentatively proposed an implementation timeline that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) “Self-Insurance” letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) “Proposal” letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) “Order” letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a “tailored plan” for posting additional security over a phased-in period of time, (B) within 60 days of such letter, provide additional security for “sole liability” properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan).

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We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are not eligible to self-insure any of our additional security obligations. We received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required, and we are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of BSEE's. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. The revised proposed plan we submitted to BOEM may require approximately $7 million to $10 million of incremental financial assurance or bonding for sole liability properties and potentially an additional $30 million to $60 million of incremental financial assurance or bonding for non-sole liability properties by the end of 2017 or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL. Under the revised proposed plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. Additionally, it is uncertain at this time what impact the new Trump administration may have on the current financial regulatory framework. Compliance with the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, 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.

If fully implemented, the new NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which will in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator's collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations. See Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Natural Gas. In 2005, the United States Congress enacted the Energy Policy Act of 2005 ("EPAct 2005"). Among other matters, EPAct 2005 amends the Natural Gas Act (the "NGA") to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as Stone Energy, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (the "FERC"), in contravention of rules prescribed by the FERC. In 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud, to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. The U.S. Commodity Futures Trading Commission (the "CFTC") has similar authority with respect to energy futures commodity markets. Stone Energy does not anticipate it will be affected any differently by these requirements than other producers of natural gas.

Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The FERC has undertaken various initiatives to increase competition within the natural gas industry, including requiring interstate pipelines to provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In addition, the natural gas pipeline industry is also subject to state regulations, which may change from time to time in ways that affect the availability, terms and cost of transportation. However, we do not believe that any such changes would affect our business in a way that would be materially different from the way such changes would affect our competitors.

Oil. Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the Federal Trade Commission (the "FTC") issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale, from knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person or intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1 million per day per violation, in addition to any applicable penalty under the FTC Act.

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Our sales of crude oil, condensate and natural gas liquids ("NGL"s) are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. The price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, NGLs and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.

In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. As it relates to intrastate crude oil, condensate and NGL pipelines, state regulation is generally less rigorous than the federal regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests, which are infrequent and are usually resolved informally.

We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate and NGL pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and NGL producers or marketers.

Miscellaneous. Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by the United States Congress, state regulatory bodies, the BOEM, the BSEE, the FERC and other federal regulatory bodies and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the oil and natural gas industry has been heavily regulated. We can give no assurance that the regulatory approach currently pursued by the BOEM, the BSEE, the FERC or any other state or federal agency will continue indefinitely.

Environmental Regulation

As a lessee and operator of offshore oil and gas properties in the United States, we are subject to stringent federal, state and local laws and regulations relating to the protection of the environment, worker health and safety, and natural resources, as well as controlling the manner in which various substances, including wastes generated in connection with oil and gas industry operations, are released into the environment. Compliance with these laws and regulations may require us to obtain permits authorizing air emissions and wastewater discharge from operations and can affect the location or size of wells and facilities, limit or prohibit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties that are being abandoned. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of remedial obligations, incurrence of capital costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production operations or the disposal of substances generated in connection with oil and gas industry operation. The following is a summary of some of the existing laws, rules and regulations to which our business is subject.

Waste handling. The Resource Conservation and Recovery Act (the "RCRA") and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to regulatory guidance issued by the federal EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (the "CERCLA"), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for

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neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used in operations related to the exploration and production of oil and gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such substances have been taken for recycling or disposal. In addition, many of these properties have been operated by third parties whose storage, treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and wastes disposed thereon may be subject to laws and regulations imposing strict, joint and several liability, without regard to fault or the legality of the original conduct, that could require us to remove or remediate previously disposed wastes or environmental contamination, or to perform remedial plugging or pit closure to prevent future contamination.

Oil Pollution Act. The Oil Pollution Act of 1990 (the "OPA") and regulations adopted pursuant thereto impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the OCS. The OPA subjects owners of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages. Although defenses exist to the liability imposed by the OPA, they are limited. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of the Interior may increase this amount up to $150 million in certain situations. In addition, the BOEM has finalized rules that raise OPA’s damages liability cap from $75 million to $133.65 million. We cannot predict at this time whether the OPA will be amended further or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we could be liable for costs and damages, which could be material to our results of operations and financial position.

Climate Change. The EPA has determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases contribute to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act ("CAA"). The EPA adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources through preconstruction and operating permit requirements.

The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, on an annual basis. Recent regulation of emissions of greenhouse gases has focused on fugitive methane emissions. For example, in June 2016, the EPA finalized rules that establish new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions.

In addition, while the United States Congress has not taken any legislative action to reduce emissions of greenhouse gases, many states have established greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Substantial limitations on greenhouse gas emissions could also adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such climate changes were to occur, they could have an adverse effect on our financial condition and results of operations.

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At this time, we have not yet developed a comprehensive plan to address the legal, economic, social, or physical impacts of climate change on our operations.

Water discharges. The federal Water Pollution Control Act (the "Clean Water Act") and analogous state laws, impose restrictions and strict controls with respect to the monitoring and discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or an analogous state agency. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Air emissions. The CAA and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources, as well as the emission of other pollutants that the agency has determined pose a threat to the public health and welfare.

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard ("NAAQS") for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements for our operations that have the potential to affect state air quality, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Endangered Species. Executive Order 13158, issued in May 2000, directs federal agencies to safeguard existing Marine Protected Areas ("MPAs") in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses. Federal Lease Stipulations include regulations regarding the taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). Historically, our compliance costs for the protection of marine species have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. Certain flora and fauna that have been officially classified as "threatened" or "endangered" are protected by the Endangered Species Act ("ESA"). This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. We conduct operations on leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist.

Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Magnuson-Stevens Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within designated protected areas, wilderness or wetlands. These and other protected areas may require certain mitigation measures to avoid harm to wildlife, and such laws and regulations may impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities.

We have made, and will continue to make, expenditures in our effort to comply with environmental laws and regulations. We do not believe that compliance with applicable environmental laws and regulations will have a material adverse impact on us. However, we also believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards and, thus, we cannot give any assurance that we will not be adversely affected in the future.

We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the United States. We employ a safety, environmental and regulatory department whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions and track regulatory developments applicable to our operations, such as the ones described in the paragraphs above. Although we maintain pollution insurance to cover a portion of the costs of cleanup operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. To

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date, we believe that compliance with existing requirements of such governmental bodies has not had a material effect on our operations.

Employees

On February 23, 2017, we had 241 full-time employees. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement. We utilize the services of independent contractors to perform various daily operational duties.

Available Information

We make available free of charge on our Internet website (www.stoneenergy.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the Securities and Exchange Commission ("SEC"). We also make available on our Internet website our Code of Business Conduct and Ethics, Corporate Governance Guidelines and Audit, Compensation and Nominating and Governance Committee Charters, which have been approved by our board of directors. Copies of these documents are also available free of charge by writing us at: Chief Financial Officer, Stone Energy Corporation, P.O. Box 52807, Lafayette, LA 70505. The annual CEO certification required by Section 303A.12 of the New York Stock Exchange Listed Company Manual was submitted on June 9, 2016.

Information related to the Bankruptcy Petitions is available at a website administered by our claims agent, Epiq Systems, at http://dm.epiq11.com/StoneEnergy.

Financial Information

Our financial information is included in the consolidated financial statements and the related notes beginning on page F-1.

Forward-Looking Statements

The information in this Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of 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 in this Form 10-K.

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


•	expected results from risk-weighted drilling success;


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


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


•	our outlook on oil and natural gas prices;


•	estimates of our oil and natural gas reserves;


•	any estimates of future earnings growth;


•	the impact of political and regulatory developments;


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


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


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


•	the outcome of restructuring efforts and asset sales;


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


•	any expected results or benefits associated with our acquisitions;


•	our access to capital and our anticipated liquidity;


•	estimates of future income taxes; and


•	our business strategy and other plans and objectives for future operations.

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


•	our ability to consummate the Plan in accordance with the terms of the A&R RSA, or alternative restructuring transaction;


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


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


•	risks associated with third party motions in any bankruptcy case, which may interfere with the ability to consummate the Plan;


•	potential adverse effects of bankruptcy proceedings and emergence from bankruptcy on the Company’s liquidity or results of operations;


•	increased costs to execute a reorganization;


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


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


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


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


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


•	our future level of indebtedness, liquidity, compliance with debt covenants and our ability to continue as a going concern;


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


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


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


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


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


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


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


•	third-party interruption of sales to market;


•	inflation;


•	lack of availability and cost of goods and services;


•	market conditions relating to potential acquisition and divestiture transactions;


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


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


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


•	competition in the oil and gas industry;


•	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-K.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K 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

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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.

ITEM 1A. RISK FACTORS

Our business is subject to a number of risks including, but not limited to, those described below:

Risks Relating to Chapter 11 Proceedings

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

As a consequence of our filing for relief under Chapter 11 of the Bankruptcy Code, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, will be subject to the risks and uncertainties associated with bankruptcy. These risks include the following:


•	our ability to execute and consummate the Plan or another plan of reorganization with respect to the Chapter 11 proceedings;


•	the high costs of bankruptcy proceedings and related fees;


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


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


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


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


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


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


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


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

As of December 31, 2016, we had total indebtedness of $1,427 million. Our 2017 Convertible Notes mature on March 1, 2017, and the majority of our other outstanding indebtedness will mature within the next six years. While we anticipate substantially all of our $1,427 million of indebtedness will be discharged upon emergence from Chapter 11 bankruptcy, there is no assurance that the effectiveness of the Plan will occur on February 28, 2017 as expected, or at all.

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

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

Our capital structure will be significantly altered under the Plan. Under fresh start reporting rules that may apply to us upon the effective date of the Plan (or any alternative plan of reorganization), our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh start reporting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

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

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

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

Trading in our securities is highly speculative and poses substantial risks. Under the Plan, following effectiveness of the Plan, the holders of our existing common stock will receive their pro rata share of 5% of the common stock in the reorganized Company and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants, which interests could be further diluted by the warrants and the management incentive plan contemplated by the Plan.

The Plan, as contemplated in the A&R RSA, provides that upon the Company's emergence from Chapter 11, Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of Second Lien Notes and that the holders of the existing common stock of the Company will receive their pro rata share of 5% of the common stock in the reorganized Company and warrants for up to 15% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. Issuances of common stock (or securities convertible into or exercisable for common stock) under the management incentive plan and any exercises of the warrants for shares of common stock will dilute the voting power of the outstanding common stock and may adversely affect the trading price of such common stock.

Upon emergence from bankruptcy, the composition of our board of directors will change significantly.

Under the Plan, the composition of our board of directors will change significantly. Upon emergence, the board will be made up of seven directors selected by the Noteholders, one of which will be our Chief Executive Officer. Accordingly, six of our seven board members will be new to the Company. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

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

Assuming the Plan were effective as of the date hereof, it is estimated that two bondholders who currently hold a majority of the Notes would own a majority of our post-reorganization common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

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

The Plan and any other plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our business and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to change substantially our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain customers’ confidence in our viability as a

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continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses.

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

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

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

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

Even if the Plan or any other Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Accordingly, we cannot guarantee that the Plan or any other Chapter 11 plan of reorganization will achieve our stated goals.

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

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

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

Under U.S. federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We had net operating loss carryforwards of approximately $599 million as of December 31, 2016. We believe that our consolidated group will generate additional net operating losses for the 2017 tax year. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce our U.S. federal income tax liability is subject to certain requirements and restrictions. If we experience an "ownership change", as defined in section 382 of the Internal Revenue Code, our ability to use our pre-emergence net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an "ownership change" if one or more stockholders owning 5% or more of a corporation's common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an "ownership change", the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. Even if the net operating loss carryforwards are subject to limitation under Section 382, the net operating losses can be further reduced by the amount of discharge of indebtedness arising in a Chapter 11 case under Section 108 of the Internal Revenue Code.

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

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Business Risks

Oil and natural gas prices are volatile. Significant declines in commodity prices have adversely affected, and in the future may adversely affect, our financial condition and results of operations, cash flows, access to the capital markets and ability to grow.

Our revenues, cash flows, profitability and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds under our bank credit facility and through the capital markets. The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. The significant decline in oil and natural gas prices in the second half of 2014 continuing throughout 2015 and 2016 has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. If commodity prices remain suppressed or continue to decline in the future, it will likely have material adverse effects on our reserves and borrowing base. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices. Significant price declines could cause us to take additional ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See “—Lower oil and natural gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.”

In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. For example, in response to low commodity prices and the high cost of midstream gathering, processing, and marketing, we shut in production at our Mary field in Appalachia from September 1, 2015 until June 2016. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2013 through December 31, 2016, the West Texas Intermediate ("WTI") crude oil price per Bbl ranged from a low of $26.21 to a high of $110.53, and the New York Mercantile Exchange ("NYMEX") natural gas price per MMBtu ranged from a low of $1.64 to a high of $6.15. The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:


•	changes in the supply of and demand for oil and natural gas;


•	market uncertainty;


•	level of consumer product demands;


•	hurricanes and other weather conditions;


•	domestic and foreign governmental regulations and taxes;


•	price and availability of alternative fuels;


•	political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia, South America and Africa;


•	actions by the Organization of Petroleum Exporting Countries;


•	U.S. and foreign supply of oil and natural gas;


•	price of oil and natural gas imports; and


•	overall domestic and foreign economic conditions.

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.

Our debt level and the covenants in the current and any future agreements governing our debt, including the Amended Credit Facility and the indenture for the Second Lien Notes, could negatively impact our financial condition, results of operations and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

The terms of the current agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including:


•	incurring additional debt;


•	paying dividends on stock, redeeming stock or redeeming subordinated debt;


•	making investments;


•	creating liens on our assets;

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•	selling assets;


•	guaranteeing other indebtedness;


•	entering into agreements that restrict dividends from our subsidiary to us;


•	merging, consolidating or transferring all or substantially all of our assets; and


•	entering into transactions with affiliates.

Our level of indebtedness, and the covenants contained in current and future agreements governing our debt, including the Amended Credit Facility and the indenture for the Second Lien Notes, could have important consequences on our operations, including:


•	making it more difficult for us to satisfy our obligations under the indentures or other debt and increasing the risk that we may default on our debt obligations;


•	requiring us to dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;


•	limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;


•	limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;


•	detracting from our ability to successfully withstand a downturn in our business or the economy generally;


•	placing us at a competitive disadvantage against other less leveraged competitors; and


•	making us vulnerable to increases in interest rates because debt under our bank credit facility is at variable rates.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Lower commodity prices have negatively impacted our revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which declined significantly since mid-2014.

We depend on our bank credit facility for a portion of our future capital needs. We are required to comply with certain debt covenants and ratios under our bank credit facility. Our borrowing base under our bank credit facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values. If, due to a redetermination of our borrowing base, our outstanding bank credit facility borrowings plus our outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our current agreement with the banks allows us to cure a borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the borrowing base deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after our written election to do so and/or (3) pay the deficiency in six equal monthly installments.

We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt. The terms of our debt, including our bank credit facility and our indentures, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through offerings of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing or sale of assets will be successfully completed.

We filed for bankruptcy under Chapter 11 of the U.S. Bankruptcy Code on December 14, 2016 pursuant to the Plan. The terms of the Amended Credit Facility under the Plan are substantially consistent with the pre-petition facility, except, the borrowing base will be reduced to $200 million (subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017), subject to decrease under certain circumstances. See Bank Credit Facility below. There can be no assurance that we will emerge from bankruptcy on February 28, 2017 as expected. See Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources for additional information on our current credit facility and the Amended Credit Facility effective upon emergence from Chapter 11 bankruptcy.

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Regulatory requirements and permitting procedures imposed by the BOEM and BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

Subsequent to the Deepwater Horizon incident in the GOM in April 2010, the BOEM issued a series of NTLs imposing regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These regulatory requirements include the following:


•	the Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;


•	the Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes and also requires certifications of compliance from senior corporate officers;


•	the Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and

•

the Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system ("SEMS") to reduce human and organizational errors as root causes of work-related accidents and offshore spills, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, establish procedures to provide all personnel with "stop work" authority, and to have their SEMS periodically audited by an independent third party auditor approved by the BSEE.

Since the adoption of these new regulatory requirements, the BOEM has been taking longer to review and approve permits for new wells than was common prior to the Deepwater Horizon incident. The rules also increase the cost of preparing each permit application and increase the cost of each new well, particularly for wells drilled in deeper waters of the OCS. We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the GOM if we fail to comply with the BOEM’s NTLs or other regulatory requirements. Additional federal action is likely. For example, in April 2016, BSEE issued its final well control regulations, effective July 2016, though some requirements of the rule have delayed compliance deadlines. The final rule addresses the full range of systems and equipment associated with well control operations, focusing on requirements for blowout preventers ("BOPs"), well design, well control casing, cementing, real-time monitoring and subsea containment. Key features of the well control regulations include requirements for BOPs, double shear rams, third-party reviews of equipment, real-time monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing, cementing and subsea containment. Separately, BOEM proposed new rules in April 2016 that would update existing air emissions requirements relating to offshore oil and natural gas activity on federal OCS waters including in the Central Gulf of Mexico. BOEM regulates these air emissions in connection with its review of exploration and development plans, and right-of-use and right-of-way applications. The proposed rule would bolster existing air emission reporting requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. Compliance with new and future regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, under certain circumstances, the BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect our financial condition and operations.

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

BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we and many other operators have been able to obtain an exemption from most bonding obligations based on financial net worth. On March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $118 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates.

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In July 2016, BOEM issued a new NTL, with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurance by offshore lessees. The NTL discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self-insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and, consistent with those procedures, BOEM has tentatively proposed an implementation timeline that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) Self-Insurance letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) Proposal letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) Order letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a tailored plan for posting additional security over a phased-in period of time, (B) within 60 days of such letter, provide additional security for sole liability properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan).

We received a Self-Insurance letter from BOEM dated September 30, 2016 stating that we are not eligible to self-insure any of our additional security obligations. We received a Proposal letter from BOEM dated October 20, 2016 indicating that additional security may be required, and we are continuing to work with BOEM to adjust our previously submitted tailored plan for variances between our decommissioning estimates and that of BSEE's. In the first quarter of 2017, BOEM announced that it will extend the implementation timeline for the new NTL by an additional six months. The revised proposed plan may require approximately $7 million to $10 million of incremental financial assurance or bonding for sole liability properties and potentially an additional $30 million to $60 million of incremental financial assurance or bonding for non-sole liability properties by the end of 2017 or in 2018, dependent on adjustments following ongoing discussions with BSEE and any modifications to the NTL. Under the revised proposed plan, additional financial assurance would be required for subsequent years. There is no assurance this tailored plan will be approved by BOEM, and BOEM may require further revisions to our plan. Additionally, it is uncertain at this time what impact the new Trump administration may have on the current financial regulatory framework. Compliance with the NTL, or any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements adversely affecting our offshore activities could delay or disrupt our operations, result in increased supplemental bonding and costs, 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.

In addition, if fully implemented, the new NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which will in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator’s collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our current bank credit facility or in the capital markets.

Historically, we have used our cash flows from operating activities and borrowings under our bank credit facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. In the future, we may not be able to access adequate funding under our bank credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our bank credit facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, an increased counterparty credit risk on our derivatives contracts and the requirement by contractual counterparties of us to post collateral guaranteeing performance.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and natural gas reserves. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity financing will be available or cash flows provided by operations will be sufficient to meet these requirements. For

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example, the ability of oil and gas companies to access the equity and high yield debt markets has been significantly limited since the significant decline in commodity prices since mid-2014.

Following the disposition of the Appalachia Properties, our production, revenue and cash flow from operating activities will be derived from assets that are concentrated in a single geographic area in the GOM. Unlike other entities that are geographically diversified, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate and result in our dependency upon a single or limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the GOM and the U.S. Gulf Coast will mean that some or all of the properties could be affected should the region experience:

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

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

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


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

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

We may experience significant shut-ins and losses of production due to the effects of hurricanes in the GOM.

Following the sale of the Appalachia Properties, our production will be exclusively associated with our properties in the GOM and the U.S. Gulf Coast. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the GOM. In past years, we have experienced shut-ins and losses of production due to the effects of hurricanes in the GOM. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses.

We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, oil pollution, construction all risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses.

Currently, we have general liability insurance coverage with an annual aggregate limit of $825 million on a 100% working interest basis. We no longer purchase physical damage insurance coverage for our platforms for losses resulting from named windstorms. Additionally, we now purchase physical damage insurance coverage for losses resulting from operational activities for only our Amberjack and Pompano platforms. We have continued purchasing physical damage insurance coverage for operational losses for a selected group of pipelines, including the majority of the pipelines and umbilicals associated with our Amberjack and Pompano facilities.

Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $20 million to $500 million per occurrence. Exploratory deep water wells have a coverage limit of up to $600 million per occurrence. Additionally, we currently maintain $150 million in oil pollution liability coverage. Our operational control of well and physical damage policy limits are scaled proportionately to our working interests. Our general liability program utilizes a combination of assureds interest and scalable limits. All of our policies described above are subject to deductibles, sub-limits or self-insurance. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

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An operational or hurricane-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. In past years, we have experienced production interruptions for which we had no production interruption insurance.

We reevaluate the purchase of insurance, policy limits and terms annually in May through July. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the GOM, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Lower oil and natural gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, we compare, at the end of each financial reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a trailing twelve-month average, hedge-adjusted commodity price 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 estimated discounted future net cash flows. A write-down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. For example, oil and natural gas prices declined significantly during the second half of 2014 continuing throughout 2015 and 2016. We recorded non-cash ceiling test write-downs of approximately $351 million, $1,362 million and $357 million for the years ended December 31, 2014, 2015 and 2016, respectively. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future and incur additional charges against future earnings.

Our oil and gas operations are subject to various U.S. federal, state and local governmental regulations that materially affect our operations.

Our oil and gas operations are subject to various U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can release materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity. In addition, the OPA requires operators of offshore facilities such as us to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under the OPA and other environmental statutes such as CERCLA and RCRA and analogous state laws, owners and operators of certain defined onshore and offshore facilities are strictly liable for spills of oil and other regulated substances, subject to certain limitations. Consequently, a substantial spill from one of our facilities subject to laws such as the OPA, CERCLA and RCRA could require the expenditure of additional, and potentially significant, amounts of capital, or could have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances, and materials produced or used in connection with oil and gas operations. We cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations or competitive position.

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

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

On April 29, 2016, we were notified by the NYSE that the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days. On May 17, 2016, we were notified by the NYSE that our average global market capitalization had been less than $50 million over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50 million.

On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock in order to increase the per share trading price of our common stock in order to regain compliance with the NYSE’s minimum share price requirement. We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the $1.00 per share average closing price requirement. We remain non-compliant with the $50 million average market capitalization and stockholders’ equity requirements.

On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders’ equity deficiencies to the NYSE. After our submission of the business plan, the NYSE had 45 calendar days to review the plan to determine whether we have made reasonable demonstration of our ability to come into conformity with the relevant standards within the 18-month period. The NYSE accepted the plan on August 4, 2016 and will continue to review the Company on a quarterly basis for compliance with the plan. Upon acceptance of the plan by the NYSE, and after two consecutive quarters of sustained market capitalization above $50 million, we would no longer be non-compliant with the market capitalization and stockholders' equity requirements. During the 18-month cure period, our shares of common stock will continue to be listed and traded on the NYSE, unless we experience other circumstances that subject us to delisting. If we fail to meet the material aspects of the plan or any of the quarterly milestones, the NYSE will review the circumstances causing the variance, and determine whether such variance warrants commencement of suspension and delisting procedures. Additionally, under Section 802.01D of the NYSE Listed Company Manual, if a company that is below a continued listing standard files or announces an intent to file for relief under Chapter 11 of the Bankruptcy Code, the company is subject to immediate suspension and delisting. However, if we are profitable or have positive cash flow, or if we are demonstrably in sound financial health despite the bankruptcy proceedings, the NYSE may evaluate our plan in light of the filing without immediate suspension and delisting of our common stock. To date, and throughout the Chapter 11 filing period, we have continued to trade on the NYSE.

On September 20, 2016, we submitted our quarterly update to the business plan for the second of quarter 2016, and the NYSE notified us that it accepted the quarterly update on September 22, 2016. On December 22, 2016, we submitted our quarterly update to the business plan for the third quarter of 2016, and the NYSE notified us that it accepted the quarterly update on January 5, 2017.

In addition to potentially commencing suspension or delisting procedures in respect of our common stock if we fail to meet the material aspects of the plan or any of the quarterly milestones or if we file for bankruptcy and do not have positive cash flow or are not in sound financial health, our common stock could be delisted pursuant to Section 802.01 of the NYSE Listed Company Manual if the trading price of our common stock on the NYSE is abnormally low, which has generally been interpreted to mean at levels below $0.16 per share, and our common stock could also be delisted pursuant to Section 802.01 if our average market capitalization over a consecutive 30 day-trading period is less than $15 million. In these events, we would not have an opportunity to cure the market capitalization deficiency, and our shares would be delisted immediately and suspended from trading on the NYSE.

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

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Additional issuances of equity securities by us would dilute the ownership of our existing stockholders and could reduce our earnings per share.

The Plan provides, among other things, that upon emergence from bankruptcy, our existing common stock will be cancelled and (i) the Noteholders will receive their pro rata share of 95% of the common stock in reorganized Stone and (ii) existing holders of common stock in Stone will receive their pro rata share of 5% of the common stock in reorganized Stone, plus warrants for ownership of up to 15% of reorganized Stone's common equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan.

Additionally, we may issue equity in the future in connection with capital raisings, debt exchanges, acquisitions, strategic transactions or for other purposes. To the extent we issue substantial additional equity securities, the ownership of our existing stockholders would be diluted, and our earnings per share could be reduced.

We may not be able to replace production with new reserves.

In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. GOM reservoirs tend to be recovered quickly through production with associated steep declines, while declines in other regions after initial flush production tend to be relatively low. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.

Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, current market conditions have adversely impacted our ability to obtain financing to fund acquisitions, and they have lowered the level of activity and depressed values in the oil and natural gas property sales market.

Production periods or reserve lives for GOM properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

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

Our actual recovery of reserves may substantially differ from our proved reserve estimates.

This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this Form 10-K and the information incorporated by reference. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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You should not assume that any present value of future net cash flows from our proved reserves contained in this Form 10-K represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2016 on historical twelve-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production and changes in governmental regulations or taxes. At December 31, 2016, approximately 20% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumptions that we will incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

Our acreage must be drilled before lease expiration in order to hold the acreage by production. If commodity prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage may expire. We have leases on 18,777 gross acres (9,970 net) that could potentially expire during fiscal year 2017. See Item 2. Properties – Productive Well and Acreage Data.

Our drilling plans for areas not currently held by production are subject to change based upon various factors. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling, therefore there is additional risk of expirations occurring in those sections.

The marketability of our production depends mostly upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities.

The marketability of our production depends upon the availability, proximity, operation and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of these gathering systems, pipelines and processing facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. The disruption of these gathering systems, pipelines and processing facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. Federal, state and local regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors changed dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.

Our actual production could differ materially from our forecasts.

From time to time, we provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts may assume that none of the risks associated with our oil and gas operations summarized in this Item 1A occur, such as facility or equipment malfunctions, adverse weather effects, or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.

Our operations are subject to numerous risks of oil and gas drilling and production activities.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves will be found. The cost of drilling and completing wells is often uncertain. To the extent we drill additional wells in the GOM deep water and/or in the Gulf Coast deep gas, our drilling activities could become more expensive. In addition, the geological complexity of GOM deep water, Gulf Coast deep gas and various onshore formations may make it more difficult for us to sustain our historical rates of drilling success. Oil and gas drilling and production activities may be shortened, delayed or cancelled as a result of a variety of factors, many of which are beyond our control. These factors include:


•	unexpected drilling conditions;


•	pressure or irregularities in formations;


•	equipment failures or accidents;


•	hurricanes and other weather conditions;

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•	shortages in experienced labor; and


•	shortages or delays in the delivery of equipment.

The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient cash flows to recoup drilling costs.

Our industry experiences numerous operating risks.

The exploration, development and production of oil and gas properties involves a variety of operating risks including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. We are also involved in drilling operations that utilize hydraulic fracturing, which may potentially present additional operational and environmental risks. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions, including the effects of hurricanes.

We explore for oil and natural gas in the deep waters of the GOM (water depths greater than 2,000 feet). Exploration for oil or natural gas in the deepwater of the GOM generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.

Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, the implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the GOM is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change, or more restrictive interpretation and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the GOM, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes.

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The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the GOM following BSEE’s issuance of an NTL that established a more stringent regimen for the timely decommissioning of what is known as "idle iron" wells, which are platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the GOM. The idle iron NTL requires decommissioning of any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities, which must then be permanently plugged or temporarily abandoned within three years’ time. Similarly, platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. We may have to draw on funds from other sources to satisfy decommissioning costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations. Moreover, as a result of the implementation of the idle iron NTL, there is expected to be increased demand for salvage contractors and equipment operating in the GOM, resulting in increased estimates of plugging, abandonment and removal costs and associated increases in operators’ asset retirement obligations.

We may not receive payment for a portion of our future production.

We may not receive payment for a portion of our future production. We have attempted to diversify our sales and obtain credit protections, such as parental guarantees, from certain of our purchasers. The tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by customers. We are unable to predict what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.

There are uncertainties in successfully integrating our acquisitions.

Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results.

Competition within our industry may adversely affect our operations.

Competition within our industry is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from the BOEM are acquired through a "sealed bid" process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. The competitors may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent upon key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have an adverse effect on us and our operations.

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Our Certificate of Incorporation and Bylaws and the Delaware General Corporation Law have provisions that, alone or in combination with each other, discourage corporate takeovers and could prevent stockholders from realizing a premium on their investment.

Certain provisions of our Certificate of Incorporation and Bylaws and the provisions of the Delaware General Corporation Law may encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. Our Certificate of Incorporation authorizes our board of directors to issue preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as our board of directors may determine. Additional provisions of our Certificate of Incorporation and of the Delaware General Corporation Law, alone or in combination with each other, include restrictions on business combinations and the availability of authorized but unissued common stock. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.

We may issue shares of preferred stock with greater rights than our common stock.

Our Certificate of Incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, liquidation rights or voting rights. If we issue preferred stock, it may adversely affect the market price of our common stock.

Resolution of litigation could materially affect our financial position and results of operations.

We have been named as a defendant in certain lawsuits. See Item 3. Legal Proceedings. In some of these suits, our liability for potential loss upon resolution may be mitigated by insurance coverage. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we could incur losses that could be material to our financial position or results of operations in future periods. We may also become involved in litigation over certain issues related to the Plan, including the proposed treatment of certain claims thereunder. The outcome of such litigation could have a material impact on our financial position or results of operations in future periods.

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.

Climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

The EPA has determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases contribute to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources through preconstruction and operating permit requirements.

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processing, transmission and storage activities. The EPA’s rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act"), enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated "bona fide hedging" transactions or positions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered into to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.

The full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, or reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Act and regulations implementing the Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a

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consequence of the Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

Hedging transactions may limit our potential gains or become ineffective.

In order to manage our exposure to price risks in the marketing of our oil and natural gas, we periodically enter into oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedging policy provides that, without prior approval of our board of directors, generally not more than 60% of our estimated production quantities may be hedged for any given year. These arrangements may include futures contracts on the NYMEX or the Intercontinental Exchange. While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:


•	our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;


•	there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;


•	the counterparties to our futures contracts fail to perform the contracts;


•	a sudden, unexpected event materially impacts oil or natural gas prices; or


•	we are unable to market our production in a manner contemplated when entering into the hedge contract.

Currently, all of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our bank credit facility. Our existing derivative agreements with the lenders are secured by the security documents executed by the parties under our bank credit facility. Future collateral requirements for our commodity hedging activities are uncertain and will depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions.

Terrorist attacks aimed at our facilities could adversely affect our business.

The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our financial condition and operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

As of December 31, 2016, our property portfolio consisted of eight active properties and 68 primary term leases in the GOM Basin, three active properties in the Appalachia region and inactive undeveloped acreage in the Rocky Mountain region. In connection with our restructuring efforts, we entered into a purchase and sale agreement to sell the Appalachia Properties. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions, after which we will no longer have operations or assets in Appalachia. See Item 1. Business – Operational Overview. The properties that we currently operate accounted for 93% of our year-end 2016 estimated proved reserves. This high operating percentage allows us to better control the timing, selection and costs of our drilling and production activities. Information on our significant properties is included below.

Oil and Natural Gas Reserves

Our Reserves Committee Charter provides that the reserves committee has the sole authority to recommend to our board of directors appointments or replacements of one or more firms of independent reservoir engineers and geoscientists. The reserves committee reviews annually the arrangements of the independent reservoir engineers and geoscientists with management, including the scope and general extent of the examination of our reserves, the reports to be rendered, the services and fees and consideration of the independence of such independent reservoir engineers and geoscientists. The reserves committee may consult with management but may not delegate these responsibilities. The reserves committee provides oversight in regards to the reserve

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estimation process but not the actual determination of estimated proved reserves. Our Reserves Committee Charter provides that it is the duty of management and not the duty of the reserves committee to plan or conduct reviews or to determine that our reserve estimates are complete and accurate and are in accordance with generally accepted engineering standards and applicable rules and regulations of the SEC. Our Vice President - Planning, Marketing & Midstream is the in-house person designated as primarily responsible for the process of reserve preparation. He is a petroleum engineer with over 20 years of experience in reservoir engineering and analysis. His duties include oversight of the preparation of quarterly reserve estimates and coordination with the outside engineering consultants on the preparation of year-end reserve estimates. The year-end reserve estimates prepared by our outside engineering firm are independent of any oversight of the Vice President - Planning, Marketing & Midstream or the reserves committee.

Estimates of our proved reserves at December 31, 2016 were independently prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI letter, which is filed as an exhibit to this Form 10-K, were Lily W. Cheung, Vice President and Team Leader, and Edward C. Roy III, Vice President. Ms. Cheung is a Registered Professional Engineer in the State of Texas (License No. 107207). Ms. Cheung joined NSAI in 2007 after serving as an Engineer at ExxonMobil Production Company. Ms. Cheung’s areas of specific expertise include estimation of oil and gas reserves, drilling and workover prospect evaluation, and economic evaluations. Ms. Cheung received an MBA degree from University of Texas at Austin in 2007 and a BS degree in Mechanical Engineering from Massachusetts Institute of Technology in 2003. Mr. Roy is a Registered Professional Geoscientist in the State of Texas (License No. 2364). Mr. Roy joined NSAI in 2008 after serving as a Senior Geologist at Marathon Oil Company. Mr. Roy’s areas of specific expertise include deep-water stratigraphy, seismic interpretation and attribute analysis, volumetric reserve estimation, and probabilistic analysis. Mr. Roy received a MS degree in Geology from Texas A&M University in 1998 and a BS degree in Geology from Texas Christian University in 1992. Ms. Cheung and Mr. Roy both meet or exceed the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; they are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The following table sets forth our estimated proved oil and natural gas reserves (approximately 66% of which are located in the GOM and 34% in the Appalachia region) as of December 31, 2016. The 2016 average twelve-month oil and natural gas prices net of differentials were $40.15 per Bbl of oil, $9.46 per Bbl of NGLs and $1.71 per Mcf of natural gas.



Summary of Oil, Natural Gas and NGL Reserves as of
December 31, 2016
	Oil (MBbls)	NGLs (MBbls)	Natural Gas (MMcf)	Oil, Natural Gas and NGLs (MMcfe)
Reserves Category:
PROVED
Developed	18,269	9,255	90,741	255,884
Undeveloped	5,011	1,374	26,579	64,889
TOTAL PROVED	23,280	10,629	117,320	320,773

At December 31, 2016, we reported estimated proved undeveloped reserves ("PUDs") of 64.9 Bcfe, which accounted for 20% of our total estimated proved oil and natural gas reserves. This figure ties to a projected four new wells (60.2 Bcfe) and one sidetrack well from an existing wellbore (4.7 Bcfe). The timetable for drilling this sidetrack well is totally dependent on the life of the currently producing zone. After the current zone has been depleted, we would utilize the existing wellbore to sidetrack to the PUD objective. Regarding the remaining four PUD locations, we project three wells to be drilled in 2017 (52.1 Bcfe) and one well in 2018 (8.1 Bcfe). None of these four PUD wells will have been on our books in excess of five years at the time of their scheduled drilling. The following table discloses our progress toward the conversion of PUDs during 2016.

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	Oil, Natural Gas and NGLs (MMcfe)		Future Development Costs (in thousands)
PUDs beginning of year	92,894		$	181,954
Revisions of previous estimates	(11,051	)	(15,216		)
Conversions to proved developed reserves	(16,954	)	(37,766		)
Additional PUDs added	—		—
PUDs end of year	64,889		$	128,972

During 2016, we invested approximately $37.8 million to convert 17.0 Bcfe of PUDs to proved developed reserves in the GOM. As of December 31, 2016, we had no PUDs in the Appalachia region.

The following represents additional information on our significant properties:



			December 31, 2016
		2016	Estimated
Field Name	Location	Production (MMcfe)	Proved Reserves (MMcfe)	Nature of Interest
Pompano (1)	GOM Deep Water	32,629	142,302	Working
Mary (2)	Appalachia	20,850	101,227	Working
Mississippi Canyon Block 109	GOM Deep Water	6,386	37,641	Working
Bayou Hebert	Gulf Coast Deep Gas	3,916	14,064	Working
Main Pass Block 288	GOM Shelf	3,554	10,533	Working
Ship Shoal Block 113	GOM Shelf	4,668	6,821	Working
Heather (2)	Appalachia	7,169	5,931	Working

(1)

Production volumes include the Pompano, Cardona and Amethyst fields, all of which tie back to the Pompano platform. Estimated proved reserves include the Pompano and Cardona fields. The Amethyst well was shut-in during late April 2016 to allow for a technical evaluation. Intervention operations were unsuccessful and there were no estimated proved reserves booked at December 31, 2016. We expect to begin temporary abandonment operations on the well in late February 2017, and we will evaluate the well for potential sidetrack operations in the second half of 2017. The estimated proved reserves associated with the Amethyst well at year-end 2015 were approximately 78,870 MMcfe.


(2)	At December 31, 2015, all of our Mary field reserves were removed from proved reserves due to the effect of reduced commodity prices. In late June 2016, we entered into an interim Appalachian midstream contract whereby we elected to resume production at the Mary field.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein only represents estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geological success, prices, future production levels, operating costs, development costs and income taxes that may not prove to be correct. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of these estimates depends on the accuracy of the assumptions upon which they are based.

As an operator of domestic oil and gas properties, we have filed U.S. Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The differences are attributable to the fact that Form EIA-23 requires that an operator report the total reserves attributable to wells that it operates, without regard to percentage ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis) or non-operated wells in which it owns an interest.

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Acquisition, Production and Drilling Activity

Acquisition and Development Costs. The following table sets forth certain information regarding the costs incurred in our acquisition, development and exploratory activities in the United States and Canada during the periods indicated.



	Year Ended December 31,
	2016		2015			2014
	(In thousands)
Acquisition costs, net of sales of unevaluated properties	$	3,425	$	(17,020	)	$	51,590
Exploratory costs	20,059		112,936			289,890
Development costs (1)	102,665		266,982			438,334
Subtotal	126,149		362,898			779,814
Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements	47,866		68,410			76,363
Total additions to oil and gas properties, net	$	174,015	$	431,308		$	856,177


(1)	Includes capitalized asset retirement costs of ($4,461), ($43,901) and ($20,305) for the years ended December 31, 2016, 2015 and 2014, respectively.

Production Volumes, Sales Price and Cost Data. The following table sets forth certain information regarding our production volumes, sales prices and average production costs for the periods indicated.



	Year Ended December 31,
	2016		2015		2014
Production:
Oil (MBbls)	6,308		5,991		5,568
Natural gas (MMcf)	29,441		36,457		47,426
NGLs (MBbls)	2,183		2,401		2,114
Oil, natural gas and NGLs (MMcfe)	80,387		86,809		93,518
Average sales prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	40.82	$	46.88	$	91.27
Natural gas (per Mcf)	1.80		1.90		3.67
NGLs (per Bbl)	13.23		13.46		40.51
Oil, natural gas and NGLs (per Mcfe)	4.22		4.40		8.21
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	44.59	$	69.52	$	92.69
Natural gas (per Mcf)	2.19		2.29		3.51
NGLs (per Bbl)	13.23		13.46		40.51
Oil, natural gas and NGLs (per Mcfe)	4.66		6.13		8.21
Expenses (per Mcfe):
Lease operating expenses (1)	$	0.99	$	1.15	$	1.89
Transportation, processing and gathering expenses	0.35		0.68		0.69


(1)	Includes oil and gas operating costs and major maintenance expense and excludes production taxes.

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Production Volumes, Sales Price and Cost Data for Individually Significant Fields. The following tables set forth certain information regarding our oil, natural gas and NGL production volumes, sales prices and average production costs for the periods indicated for any field(s) containing 15% or more of our total estimated proved reserves at December 31, 2016.



	Year Ended December 31,
FIELD: Pompano (1)	2016		2015		2014
Production:
Oil (MBbls)	3,858		2,994		1,311
Natural gas (MMcf)	7,882		3,466		2,894
NGLs (MBbls)	267		245		151
Oil, natural gas and NGLs (MMcfe)	32,629		22,902		11,666
Average sales prices:
Oil (per Bbl)	$	41.86	$	49.18	$	92.53
Natural gas (per Mcf)	2.15		2.17		3.10
NGLs (per Bbl)	12.46		15.28		41.27
Oil, natural gas and NGLs (per Mcfe)	5.57		6.92		11.70
Expenses (per Mcfe):
Lease operating expenses (2)	$	0.78	$	0.91	$	2.75
Transportation, processing and gathering expenses	0.10		0.07		0.13


(1)	Includes the Pompano, Cardona and Amethyst fields, all of which tie back to the Pompano platform.


(2)	Includes oil and gas operating costs and major maintenance expense and excludes production taxes.



	Year Ended December 31,
FIELD: Mary (1)	2016		2015		2014
Production:
Oil (MBbls)	278		464		525
Natural gas (MMcf)	10,012		16,764		17,974
NGLs (MBbls)	1,528		1,583		1,247
Oil, natural gas and NGLs (MMcfe)	20,850		29,050		28,605
Average sales prices:
Oil (per Bbl)	$	32.91	$	26.35	$	51.72
Natural gas (per Mcf)	1.61		1.77		3.55
NGLs (per Bbl)	11.99		11.04		38.86
Oil, natural gas and NGLs (per Mcfe)	2.09		2.05		4.88
Expenses (per Mcfe):
Lease operating expenses (2)	$	0.47	$	0.48	$	0.55
Transportation, processing and gathering expenses	0.86		1.35		1.50


(1)	The Mary field was shut in from September 2015 through June 2016.


(2)	Includes oil and gas operating costs and major maintenance expense and excludes production taxes.

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Drilling Activity. The following table sets forth our drilling activity for the periods indicated.



	Year Ended December 31,
	2016		2015		2014
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive	—	—	2	0.25	5	4.31
Dry	—	—	2	0.42	2	0.90
Development Wells:
Productive	1	0.65	7	5.81	38	33.35
Dry	—	—	—	—	—	—

Productive Well and Acreage Data. The following table sets forth certain statistics regarding the number of productive wells as of December 31, 2016.



	Gross	Net
Productive Wells:
Oil (1):
Deep Water	48	43
Deep Gas	—	—
Conventional Shelf	27	27
Appalachia	—	—
	75	70
Gas:
Deep Water	1	1
Deep Gas	4	1
Conventional Shelf	6	5
Appalachia	138	98
	149	105
Total productive wells	224	175

The following table sets forth certain statistics regarding developed and undeveloped acres as of December 31, 2016.



	Gross	Net
Developed Acres:
Deep Water	97,920	61,907
Deep Gas	24,729	1,702
Conventional Shelf	72,657	50,334
Appalachia	48,822	40,084
Other	8,356	2,642
	252,484	156,669
Undeveloped Acres (2):
Deep Water	325,440	206,376
Deep Gas	6,062	2,924
Conventional Shelf	5,132	5,113
Appalachia	55,999	43,689
Other	4,309	1,104
	396,942	259,206
Total developed and undeveloped acres	649,426	415,875

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(1) 5 gross wells each have dual completions.

(2) Leases covering approximately 5% of our undeveloped gross acreage will expire in 2017, 36% in 2018, 21% in 2019, 12% in 2020, 5% in 2021, 8% in 2022, and 7% in 2023.

As of December 31, 2016, none of our PUDs were assigned to locations that are currently scheduled to be drilled after lease expiration.

Title to Properties

We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we perform a title investigation that is thorough but less vigorous than that conducted prior to drilling, which is consistent with standard practice in the oil and gas industry. Before we commence drilling operations, we conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations. We have performed a thorough title examination with respect to substantially all of our active properties.

ITEM 3. LEGAL PROCEEDINGS

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

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

In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines ("Plaquemines Parish"), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. On November 12, 2015, the Plaquemines Parish Council passed a resolution instructing its attorneys to dismiss all 21 CZM suits filed by the Plaquemines Parish. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. Shortly after Stone filed a suggestion of bankruptcy in December 2016, Plaquemines Parish dismissed its CZM suit against Stone without prejudice to refiling.

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

On February 4, 2016, ICO Marcellus I, LLC ("ICO") and B&R Holdings, Inc. ("B&R") filed a lawsuit against Stone in Wetzel County, West Virginia, alleging that Stone breached the applicable joint venture agreement and joint operating agreement between the parties. On November 17, 2016, the lawsuit was dismissed based upon the parties’ resolution of all claims. Stone made a cash payment to and was assigned certain interests from ICO and B&R as part of the settlement.

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

Chapter 11 Proceedings

On December 14, 2016, the Debtors filed Bankruptcy Petitions in the United States Bankruptcy Court for the Southern District of Texas, Houston Division seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect pre-petition liabilities or to exercise control over the property of the Debtors. The Plan in our Chapter 11 proceedings provides for the treatment of pre-petition liabilities that have not otherwise been satisfied or addressed during the Chapter 11 cases. On February 15, 2017, the Bankruptcy Court entered an order confirming the Company's plan of reorganization. We expect the Plan to become effective on February 28, 2017, at which point the Debtors would emerge from bankruptcy, however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all. For additional information on the bankruptcy proceedings, see Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Since July 9, 1993, our common stock has been listed on the NYSE under the symbol "SGY." The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock. All share prices reflect the 1-for-10 reverse stock split with respect to our common stock which we completed on June 10, 2016 in order to increase the per share trading price of our common stock in order to regain compliance with the NYSE's minimum share price requirement.



	High		Low
2015
First Quarter	$	189.80	$	120.70
Second Quarter	196.50		123.30
Third Quarter	125.00		37.40
Fourth Quarter	98.40		30.60
2016
First Quarter	$	46.60	$	6.80
Second Quarter	13.50		2.70
Third Quarter	25.50		8.42
Fourth Quarter	12.50		3.69
2017
First Quarter (through February 21, 2017)	$	9.95	$	6.25

On February 21, 2017, the last reported sales price of our common stock on the New York Stock Exchange Composite Tape was $6.62 per share. As of that date, there were 336 holders of record of our common stock.

Dividend Restrictions

In the past, we have not paid cash dividends on our common stock, and we do not intend to pay cash dividends on our common stock in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and development of our business. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the indentures executed in connection with our 2017 Convertible Notes and our 2022 Notes. In addition, our bank credit facility contains provisions that prohibit the payment of dividends. We expect that the Amended Credit Facility and the indenture for the Second Lien Notes also will contain limitations or prohibitions on the payment of dividends.

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Issuer Purchases of Equity Securities

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



Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
October 1 – October 31, 2016	804	$	4.10	—
November 1 – November 30, 2016	1,619	4.03		—
December 1 – December 31, 2016	—	—		—
	2,423	$	4.05	—	$	92,928,632


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


(2)	There were no repurchases of our common stock under our share repurchase program during the fourth quarter of 2016.

Equity Compensation Plan Information

Please refer to Item 12 of this Form 10-K for information concerning securities authorized under our equity compensation plan.

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Stock Performance Graph

As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:


1.	$100 was invested in the Company’s common stock, the Standard & Poor’s 500 Stock Index ("S&P 500 Index") and the Peer Group (as defined below) on December 30, 2011 at $26.38 per share for the Company’s common stock and at the closing price of the stocks comprising the S&P 500 Index and the Peer Group, respectively, on such date.


2.	Peer Group investment is weighted based upon the market capitalization of each individual company within the Peer Group at the beginning of the period.


3.	Dividends are reinvested on the ex-dividend dates.



Measurement Period (Fiscal Year Covered)	SGY	2016 Peer Group	S&P 500 Index
12/31/2012	77.79	91.93	116.00
12/31/2013	131.12	121.45	153.57
12/31/2014	63.99	81.23	174.60
12/31/2015	16.26	48.42	177.01
12/31/2016	2.71	68.01	198.18

The companies that comprised our Peer Group in 2016 were: Cabot Oil & Gas Corporation, Callon Petroleum Company, Carrizo Oil & Gas, Inc., Cimarex Energy Company, Comstock Resources, Inc., Contango Oil & Gas Company, Denbury Resources Inc., Energy XXI Ltd., Exco Resources Inc., Newfield Exploration Company, PDC Energy, PetroQuest Energy, Inc., Range Resources Corporation, SandRidge Energy, Inc., SM Energy Company, Swift Energy Company, Ultra Petroleum Corporation, W&T Offshore, Inc. and Whiting Petroleum Corporation. The 2016 Peer Group was the same as our 2015 peer group.

The information in this Form 10-K appearing under the heading "Stock Performance Graph" is being "furnished" pursuant to Item 2.01(e) of Regulation S-K under the Securities Act and shall not be deemed to be "soliciting material" or "filed" with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2016. This information is derived from our consolidated financial statements and the notes thereto. Certain prior year amounts have been reclassified to conform to current year presentation. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.



	Year Ended December 31,
	2016			2015			2014			2013			2012
Income Statement Data:	(In thousands, except per share amounts)
Operating revenue:
Oil production	$	281,246		$	416,497		$	516,104		$	715,104		$	761,304
Natural gas production	64,601			83,509			166,494			190,580			134,739
Natural gas liquids production	28,888			32,322			85,642			60,687			48,498
Other operational income	2,657			4,369			7,951			7,808			3,520
Derivative income, net	—			7,952			19,351			—			3,428
Total operating revenue	377,392			544,649			795,542			974,179			951,489
Operating expenses:
Lease operating expenses	79,650			100,139			176,495			201,153			215,003
Transportation, processing, gathering expenses	27,760			58,847			64,951			42,172			21,782
Production taxes	3,148			6,877			12,151			15,029			10,015
Depreciation, depletion and amortization	220,079			281,688			340,006			350,574			344,365
Write-down of oil and gas properties	357,431			1,362,447			351,192			—			—
Accretion expense	40,229			25,988			28,411			33,575			33,331
Salaries, general and administrative expenses	58,928			69,384			66,451			59,524			54,648
Franchise tax settlement	—			—			—			12,590			—
Incentive compensation expense	13,475			2,242			10,361			15,340			8,113
Restructuring fees	29,597			—			—			—			—
Other operational expenses	55,453			2,360			862			151			267
Derivative expense, net	810			—			—			2,090			—
Total operating expenses	886,560			1,909,972			1,050,880			732,198			687,524
Income (loss) from operations	(509,168		)	(1,365,323		)	(255,338		)	241,981			263,965
Other (income) expenses:
Interest expense	64,458			43,928			38,855			32,837			30,375
Interest income	(550		)	(580		)	(574		)	(1,695		)	(600		)
Other income	(1,439		)	(1,783		)	(2,332		)	(2,799		)	(1,805		)
Other expense	596			434			274			—			—
Loss on early extinguishment of debt	—			—			—			27,279			1,972
Reorganization items	10,947			—			—			—			—
Total other expenses	74,012			41,999			36,223			55,622			29,942
Income (loss) before income taxes	(583,180		)	(1,407,322		)	(291,561		)	186,359			234,023
Income tax provision (benefit)	7,406			(316,407		)	(102,018		)	68,725			84,597
Net income (loss)	$	(590,586	)	$	(1,090,915	)	$	(189,543	)	$	117,634		$	149,426
Basic earnings (loss) per share	$	(105.63	)	$	(197.45	)	$	(35.95	)	$	23.58		$	30.31
Diluted earnings (loss) per share	$	(105.63	)	$	(197.45	)	$	(35.95	)	$	23.56		$	30.28
Cash dividends declared per share	—			—			—			—			—
Cash Flow Data:
Net cash provided by operating activities	$	78,588		$	247,474		$	401,141		$	594,205		$	509,749
Net cash used in investing activities	(238,172		)	(321,290		)	(872,587		)	(623,036		)	(568,688		)
Net cash provided by financing activities	339,415			10,161			215,446			80,594			300,014
Balance Sheet Data (at end of period):
Working capital (deficit)	$	132,409		$	(8,803	)	$	226,805		$	181,255		$	300,348
Oil and gas properties, net	811,514			1,211,986			2,414,002			2,619,696			2,182,095
Total assets	1,139,483			1,410,169			3,009,857			3,238,117			2,750,987
Long-term debt, less current portion (1)	352,376			1,060,955			1,032,281			1,016,645			888,682
Stockholders’ equity	(637,282		)	(39,789		)	1,101,603			970,286			872,133

(1) Reduction in long-term debt is due to the reclassification of the Company's 2017 Convertible Notes and 2022 Notes to liabilities subject to compromise.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our financial position and results of operations for each of the years in the three-year period ended December 31, 2016. Our consolidated financial statements and the notes thereto, which are found elsewhere in this Form 10-K, contain detailed information that should be referred to in conjunction with the following discussion. See Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data – Note 1.

Executive Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. In connection with our restructuring efforts, we entered into a purchase and sale agreement to sell all of our Appalachia Properties. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions, after which we will no longer have operations or assets in Appalachia. See Item 1. Business – Operational Overview.

2016 Overview

The lower commodity prices from mid-2014 through 2016 resulted in reduced revenue and cash flows and have negatively impacted our liquidity position. Additionally, the level of our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. As of December 31, 2016, we had total indebtedness of $1,427.8 million, including $300 million of 2017 Convertible Notes, $775 million of 2022 Notes, $341.5 million outstanding under our bank credit facility and $11.3 million outstanding under our Building Loan. In response to the significant decline in commodity prices, we focused on managing our balance sheet during 2016 to preserve liquidity during this extended low commodity price environment by taking certain steps, including reductions in capital expenditures and the termination and renegotiation of various contracts, reductions in workforce and reductions in discretionary expenditures. Additionally, in March 2016, we retained financial and legal advisors to assist the Company in analyzing and considering financial, transactional and strategic alternatives. We engaged in negotiations with financial advisors for the holders of the 2017 Convertible Notes and 2022 Notes regarding the restructuring of the notes and with our banks regarding an amendment to our bank credit facility.

On March 10, 2016, we borrowed $385 million under our bank credit facility, which at the time, represented substantially all of the undrawn amount on our $500 million bank credit facility. On April 13, 2016, the borrowing base under our bank credit facility was reduced by the lenders from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. In June 2016, however, we entered into the June Amendment to our bank credit facility, which among other things, resulted in an increase of our borrowing base from $300 million to $360 million and relaxed certain financial covenants through December 31, 2016. Upon execution of the June Amendment, we repaid the balance of our borrowing base deficiency, resulting in approximately $360 million outstanding under the credit facility at that time.

Production from our deep water Amethyst well was shut-in in April 2016 to allow for a technical evaluation. During the first week of November, we initiated acid stimulation work and intermittently flowed the well during the month of November at a rate of 10 – 15 million cubic feet of gas per day, while observing and evaluating the well’s performance. On November 30, 2016, we performed a routine shut-in of the well to record pressures and determined that pressure communication existed between the production tubing and production casing strings, resulting from a suspected tubing leak. Intervention operations were unsuccessful. There were no estimated proved reserve quantities booked at December 31, 2016 for the Amethyst well. We expect to begin temporary abandonment operations on the well in late February 2017, and we will evaluate the well for potential sidetrack operations in the second half of 2017. As of December 31, 2015, Amethyst represented approximately 23% and 26% of our estimated proved reserves quantities and standardized measure of discounted future net cash flows, respectively.

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2016 as well as the subsequent maturity of our 2017 Convertible Notes on March 1, 2017. As a result of these conditions, continued decreases in commodity prices and the significant level of our indebtedness, we continued to work with our financial and legal advisors throughout 2016 to structure a plan of reorganization to improve our financial position and liquidity and allow for growth and long-term success. See Liquidity and Capital Resources.

Reorganization and Chapter 11 Proceedings

On December 14, 2016, the Debtors filed the Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan. During the bankruptcy proceedings, the Debtors are operating as "debtors-in-possession" in accordance with applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by the Debtors, allowing the Company to operate its business in the ordinary course throughout the bankruptcy process. The first day motions included, among other things, a cash collateral motion, a motion maintaining the Company's existing cash management system and motions making various vendor payments, wage payments and tax payments in the ordinary course of business. Subject to certain exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Debtors or their property to recover, collect or secure a pre-petition claim. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements. We expect the Plan to become effective on February 28, 2017, at which point the Debtors would emerge from bankruptcy, however, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all.

Restructuring Support Agreement

Prior to filing the Bankruptcy Petitions, on October 20, 2016, the Debtors entered into the Original RSA with the Noteholders to support a restructuring on the terms of the Plan. On November 17, 2016, the Debtors commenced a solicitation to seek acceptance by a majority of those voting in each voting class of claims of the Company’s creditors under the Plan. The solicitation period ended on December 16, 2016 and (i) of the 94.24% of Noteholders in aggregate outstanding principal amount that voted, 99.95% voted in favor of the Plan and .05% voted to reject the Plan, and (ii) 100% of the Banks voted to accept the Plan.

On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into the A&R RSA that amended, superseded and restated in its entirety the Original RSA. In connection with entry into the A&R RSA and the commencement of the bankruptcy cases, the Debtors amended the Plan. Additionally, on December 16, 2016, the Stockholder Ad Hoc Group filed the Equity Committee Motion to appoint an official committee of equity security holders in connection with the Debtors' Chapter 11 proceedings. On December 21, 2016, the Company reached a settlement agreement with the Stockholder Ad Hoc Group and on December 28, 2016, the Plan was amended.

Upon emergence from bankruptcy by the Debtors, and pursuant to the terms of the Plan, as amended, Noteholders, Banks and other interest holders will receive treatment under the Plan, summarized as follows:


•	The Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of Second Lien Notes.

•

Existing common stockholders of Stone will receive their pro rata share of 5% of the common stock in reorganized Stone and warrants for ownership of up to 15% of reorganized Stone's common equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. The warrants will have an exercise price equal to a total equity value of the reorganized Company that implies a 100% recovery of outstanding principal to the Company’s noteholders plus accrued interest through the Plan’s effective date less the face amount of the Second Lien Notes and the Prepetition Notes Cash (as defined in the Plan). The warrants may be exercised any time prior to the fourth anniversary of the Plan’s effective date, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.

•

Banks signatory to the A&R RSA will receive their respective pro rata share of commitments and obligations under the Amended Credit Facility on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA.


•	All claims of creditors with unsecured claims other than claims by the Noteholders, including vendors, shall be unaltered and will be paid in full in the ordinary course of business to the extent such claims are undisputed.

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Each of the foregoing common equity percentages in reorganized Stone is subject to dilution from the exercise of the new warrants described above and a management incentive plan. Assuming implementation of the Plan, Stone expects that it will eliminate approximately $1.2 billion in principal amount of outstanding debt.

Purchase and Sale Agreement

The A&R RSA contained certain covenants on the part of the Company and the Noteholders and Banks who are signatories to the A&R RSA, including that such Noteholders and Banks would support the sale of the Appalachia Properties to Tug Hill, pursuant to the terms of the Tug Hill PSA, and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the A&R RSA. The consummation of the Plan is subject to customary conditions and other requirements, as well as the sale by Stone of the Appalachia Properties for a purchase price of at least $350 million and approval of the Bankruptcy Court. Pursuant to the terms of the Tug Hill PSA, Stone agreed to sell the Appalachia Properties to Tug Hill for $360 million in cash, subject to customary purchase price adjustments.

Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017, two additional bidders were allowed to participate in competitive bidding on the Appalachia Properties. On January 18, 2017, the Bankruptcy Court approved the Bidding Procedures in connection with the sale of the Appalachia Properties. In accordance with the Bidding Procedures, Stone conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT, with a final purchase price of $527 million in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court, with an upward adjustment to the purchase price of up to $16 million in an amount equal to certain downward adjustments, as the prevailing bid.

On February 9, 2017, the Company entered into the EQT PSA with EQT, reflecting the terms of the prevailing bid. Under the EQT PSA, the sale of the Appalachia Properties has an effective date of June 1, 2016. The EQT PSA contains customary representations, warranties and covenants. From and after the closing of the sale of the Appalachia Properties, the Company and EQT, respectively, have agreed to indemnify each other and their respective affiliates against certain losses resulting from any breach of their representations, warranties or covenants contained in the EQT PSA, subject to certain customary limitations and survival periods. Additionally, from and after closing of the sale of the Appalachia Properties, the Company has agreed to indemnify EQT for certain identified retained liabilities related to the Appalachia Properties, subject to certain survival periods, and EQT has agreed to indemnify the Company for certain assumed obligations related to the Appalachia Properties. The EQT PSA may be terminated, subject to certain exceptions, (i) upon mutual written consent, (ii) if the closing has not occurred by March 1, 2017, (iii) for certain material breaches of representations and warranties or covenants that remain uncured and (iv) upon the occurrence of certain other events specified in the EQT PSA.

At the close of the sale of the Appalachia Properties, the Tug Hill PSA will terminate, and the Company will use a portion of the cash consideration received to pay Tug Hill a break-up fee of $10.8 million. On February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions. Upon closing of the sale, Stone will no longer have operations or assets in Appalachia. The Appalachia Properties accounted for approximately 34% of our estimated proved oil and natural gas reserves on a volume equivalent basis at December 31, 2016.

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2017 Outlook

Upon emergence from bankruptcy, we expect that we will eliminate approximately $1.2 billion in principal amount of outstanding debt, resulting in remaining debt outstanding of approximately $236 million, consisting of the $225 million of Second Lien Notes and $11 million outstanding under the Building Loan. We expect our cash and cash equivalents to total approximately $150 million at emergence. Additionally, we will have $75 million of cash held in a restricted account to satisfy near-term plugging and abandonment liabilities, pursuant to the terms of the Amended Credit Facility. Although our capital expenditure budget for 2017 has not yet been approved by the board of directors and is dependent on the outcome of our Chapter 11 proceedings and the related reorganization of the Company, the financial projections prepared in connection with our restructuring efforts included estimated preliminary capital expenditures of approximately $200 million for 2017. The projected capital expenditures of $200 million included approximately $86 million of plugging and abandonment costs. In early 2017, we reinstated development drilling operations using a platform rig at Pompano. While management believes the Company's expected cash flows from operating activities, cash on hand and availability under the Amended Credit Facility will be adequate to meet the operating needs of the post-reorganized Company, there are no assurances that our Chapter 11 Plan, which was confirmed by the Bankruptcy Court on February 15, 2017, will become effective on February 28, 2017 as expected, or at all. Our projected 2017 capital expenditures exclude material acquisitions and capitalized salaries, general and administrative ("SG&A") expenses and interest.

Historically, we have funded our capital expenditures primarily through cash on hand, expected cash flows from operating activities and borrowings under the bank credit facility. Although we have no current plans to access the public or private equity or debt markets for purposes of capital, we may consider such funding sources to provide additional capital.

In January and February 2017, we entered into various fixed-price swaps and put contracts for a portion of our expected 2017 and 2018 oil production from the Gulf Coast Basin (see note 7 to the consolidated financial statements). In an effort to mitigate some commodity price risk, we continue to monitor the marketplace for additional hedges. Pursuant to requirements under the Plan, we expect to hedge approximately 50% of our estimated production from estimated proved producing reserves for each of 2017 and 2018.

Known Trends and Uncertainties

Fresh Start Accounting – We may be required to adopt fresh start accounting upon emergence (the "fresh start reporting date") from Chapter 11. The guidance in fresh start accounting results in the allocation of the reorganization value to individual assets based on their estimated fair values. The enterprise value of the equity of the Company at emergence will be based on several assumptions and inputs contemplated in the Plan that are subject to significant uncertainties. We currently cannot estimate the potential impact of fresh start accounting on our consolidated financial statements upon emergence from bankruptcy, although we would expect to recognize material adjustments upon implementation of fresh start accounting guidance.

Write-down of Oil and Gas Properties – We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and 2016, resulting in reduced revenue and cash flows and causing us to reduce our planned capital expenditures for 2015 and 2016. Additionally, the low commodity prices have adversely affected the estimated value and quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties. For the years ended December 31, 2014, 2015 and 2016, we recognized ceiling test write-downs of our oil and gas properties of $351 million, $1,362 million and $357 million, respectively.

If NYMEX commodity prices remain at current levels (approximately $54.00 per Bbl of oil and $2.55 per MMBtu of natural gas), we would expect an increase in the twelve-month average price used in estimating the present value of estimated future net cash flows of our proved reserves. However, we expect that the pricing differences between the trailing twelve-month average pricing assumption required by Regulation S-X, Rule 4-10 and ASC 932 used in calculating the ceiling test and the forward looking prices required by fresh start accounting to estimate the fair value of our oil and natural gas properties on the fresh start reporting date may result in an additional write-down of our oil and gas properties during the first quarter of 2017. Additionally, significant evaluations or impairments of unevaluated costs or other well performance-related revisions affecting proved reserve quantities could cause us to recognize further write-downs.

Bank Credit Facility – Throughout 2016, the level of our indebtedness and the depressed commodity price environment presented challenges as they related to our ability to comply with the covenants in the current agreements governing our indebtedness. In connection with our restructuring and pursuant to the Plan, we expect to eliminate approximately $1.2 billion in principal amount of outstanding debt upon emergence from bankruptcy, however, there can be no assurance that we will emerge from bankruptcy on February 28, 2017 as expected, or at all.

Additionally, the significant decline in commodity prices has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. The borrowing base under our bank

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credit facility as of February 23, 2017 was $360 million, a reduction from the borrowing base of $500 million as of April 12, 2016. Upon emergence from bankruptcy, the borrowing base would be further reduced under the Amended Credit Facility to $200 million, subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. See Liquidity and Capital Resources. Continued low commodity prices or further declines in commodity prices could have a further adverse impact on the estimated value and quantities of our proved reserves and could result in additional reductions of our borrowing base under our bank credit facility.

BOEM Financial Assurance Requirements – BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we and many other operators have been able to obtain an exemption from most bonding obligations based on financial net worth. On March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as $565 million. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $118 million in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates.

In addition, if fully implemented, the new NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which will in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator's collateral. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

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Although the surety companies have not historically required collateral from us to back our surety bonds, we recently provided some cash collateral on a portion of our existing surety bonds and may be required to provide additional cash collateral on existing and/or new surety bonds required by BOEM to satisfy financial assurance requirements. We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for additional bonds to comply with supplemental bonding requirements of the BOEM. This need to obtain additional surety bonds, or some other form of financial assurances, could impact our liquidity.

Hurricanes – Since a large portion of our production originates in 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 current bank credit facility.

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

Liquidity and Capital Resources

Overview

In response to the significant decline in commodity prices, we focused on managing our balance sheet during 2016 to preserve liquidity during this extended low commodity price environment by taking certain steps, including reductions in capital expenditures and the termination and renegotiation of various contracts, reductions in workforce and reductions in discretionary expenditures. On June 24, 2016, our deep water drilling rig contract with Ensco was terminated for total consideration of $20 million, approximately $5 million of which was a deposit previously provided to Ensco pursuant to the drilling services contract. To further reduce capital expenditures for 2016, we elected to temporarily stack the Pompano platform drilling rig in place. In addition, during the third quarter of 2016 we terminated an offshore vessel contract and Appalachian rig contract.

In June 2016, we entered into an interim Appalachian midstream contract with Williams at the Mary field in Appalachia, which had been shut-in since September 2015. The interim agreement provided near-term relief by permitting Stone to resume profitable production and positive cash flow at the Mary field. The initial term of the interim agreement was through August 31, 2016 and it continues on a month to month basis until the sale of the Appalachia Properties is completed. See "Purchase and Sale Agreement" above.

On April 13, 2016, the borrowing base under our bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit under the bank credit facility, resulting in a $175.3 million borrowing base deficiency. At the time, we elected to pay the deficiency in six equal installments, making the first two payments of $29.2 million in May and June 2016. On June 14, 2016, we entered into the June Amendment to, among other things, increase the borrowing base to $360 million, and on that date, we repaid $56.8 million in borrowings, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation. See "Bank Credit Facility" below.

We have $300 million of 2017 Convertible Notes that we need to restructure or repay by March 1, 2017. Additionally, we had an interest obligation under our 2022 Notes of approximately $29.2 million due on November 15, 2016 (see "Senior Notes" below). The indenture governing the 2022 Notes provides a 30-day grace period that extended the latest date for making this cash interest payment to December 15, 2016 before an event of default occurs under the indenture. Although we had sufficient liquidity to make the interest payment by the due date, we elected to not make this interest payment and utilized the 30-day grace period provided by the indenture before entering into the Chapter 11 proceedings.

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In connection with our restructuring efforts, we determined that a sale of the Appalachia Properties would be a beneficial way to maximize value for all stakeholders. On February 9, 2017, we entered into the EQT PSA to sell all of our Appalachia Properties for cash consideration of $527 million, subject to customary purchase price adjustments. On February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions.

On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into the A&R RSA, pursuant to which (1) the Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of Second Lien Notes, and (2) the Banks will receive their respective pro rata share of commitments and obligations under the Amended Credit Facility on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA. The terms of the Amended Credit Facility under the Plan are substantially consistent with the pre-petition facility, except, the borrowing base will be reduced to $200 million, subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. See Bank Credit Facility below.

The Debtors filed the Bankruptcy Petitions on December 14, 2016, and on February 15, 2017, the Bankruptcy Court entered an order confirming the Plan. We expect the Plan to become effective on February 28, 2017, at which point the Debtors would emerge from bankruptcy. While we anticipate most of our $1,427 million of indebtedness will be discharged upon emergence from Chapter 11 bankruptcy, there is no assurance that the effectiveness of the Plan will occur on February 28, 2017, or at all. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company's obligations under all of its outstanding debt instruments, resulting in the principal and interest due thereunder immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Bankruptcy Petitions, and the creditors' rights of enforcement in respect of the debt instruments were subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Although our capital expenditure budget for 2017 has not yet been approved by the board of directors and is dependent on the outcome of our Chapter 11 proceedings and the related reorganization of the Company, the financial projections prepared in connection with our restructuring efforts included estimated preliminary capital expenditures of approximately $200 million for 2017. The projected capital expenditures of $200 million included approximately $86 million of plugging and abandonment costs. In early 2017, we reinstated development drilling operations using a platform rig at Pompano. We expect that cash flows from operating activities, cash on hand and availability under the Amended Credit Facility for 2017 will be adequate to meet the operating needs of the reorganized Company; however, there are no assurances that we will emerge from bankruptcy on February 28, 2017 as expected, or at all.

Historically, we have been able to obtain an exemption from supplemental bonding requirements on our offshore leases for abandonment obligations based on financial net worth, however, on March 21, 2016, we received notice letters from BOEM stating that BOEM had determined that we no longer qualified for a supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. 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. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates.

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

Indebtedness

Bank Credit Facility – On June 24, 2014, we entered into a revolving credit facility with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019 and is guaranteed by Stone Offshore. The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. On April 13, 2016, we received notice that our borrowing base under the bank credit facility was reduced from $500 million to $300 million. On that date, we had $457 million of outstanding borrowings and $18.3 million of outstanding letters of credit, or $175.3 million in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. At that time, we elected to pay the deficiency in six equal monthly installments, making the first two payments of $29.2 million in May and June 2016.

On June 14, 2016, we entered into the June Amendment to the bank credit facility to (i) increase the borrowing base to $360 million from $300 million, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ended September 30, 2016, 9.50 to 1 for the fiscal quarter ended December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the June Amendment) of at least $125.0 million until January 15, 2017, (vi) impose limitations on capital expenditures from June through December 2016, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50.0 million to apply after December 10, 2016. Upon execution of the June Amendment, we repaid $56.8 million in borrowings under the credit facility, bringing total borrowings and letters of credit outstanding under the bank credit facility in conformity with the borrowing base limitation under the credit facility at that time. In December 2016, we reached agreements with the banks to extend the effective date of the anti-hoarding cash provisions to December 15, 2016. On February 23, 2017, we had $341.5 million of outstanding borrowings and $12.5 million of outstanding letters of credit, leaving $6.0 million of availability under the bank credit facility.

The bank credit facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage and grant a security interest in our oil and natural gas reserves representing at least 86% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Low commodity prices and negative price differentials have had a material adverse impact on the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. Continued low commodity

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prices or further declines in commodity prices will likely have a further material adverse impact on the value of our estimated proved reserves.

Interest on loans under the bank credit facility is calculated using the LIBOR rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. In addition to the covenants discussed above, the bank credit facility provides that we must maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the Credit Facility, for the preceding four quarterly periods of not less than 2.5 to 1. As of December 31, 2016, our Consolidated Funded Debt to consolidated EBITDA ratio was 6.90 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 3.24 to 1. The bank credit facility also includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.

As discussed above, on February 15, 2017, the Bankruptcy Court entered an order confirming the Company's Plan, and the Debtors expect to emerge from bankruptcy on February 28, 2017. Upon emergence, the Banks will receive their respective pro rata share of commitments and obligations under the Amended Credit Facility on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA. The terms of the Amended Credit Facility under the Plan are substantially consistent with the pre-petition facility, except, the borrowing base will be reduced to $200 million, subject to a $150 million borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. Additionally, (i) the margin for loans at the LIBOR rate will be increased to a range of 3.00% to 4.00% and (ii) our ability to pay cash dividends, prepay other indebtedness and make investments has been curtailed. Under the Amended Credit Facility we must maintain the following financial covenants: (i) a ratio of consolidated funded indebtedness to EBITDA of not greater than 3.50 to 1.00 to 2.50 to 1.00 (depending on the quarter tested); (ii) a ratio of EBITDA to net interest expense of less than 2.75 to 1.00; and (iii) liquidity (including undrawn amounts under the Amended Credit Facility) equal to 20% of the then-current borrowing base. We are required to mortgage and grant a security interest in our oil and natural gas reserves representing at least 95% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. The Amended Credit Facility will be a four-year facility.

Senior Notes – At December 31, 2016, our senior notes consisted of $300 million of 2017 Convertible Notes and $775 million of 2022 Notes. The 2017 Convertible Notes are due on March 1, 2017. As discussed above, on February 15, 2017, the Bankruptcy Court entered an order confirming the Company's Plan, and the Debtors expect to emerge from bankruptcy on February 28, 2017. Upon emergence, the $300 million and $775 million of debt related to the 2017 Convertible Notes and the 2022 Notes, respectively, will be cancelled and the Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 95% of the common stock in reorganized Stone and (c) $225 million of Second Lien Notes.

Second Lien Notes – The Second Lien Notes to be issued under the Plan will be secured by second-priority liens (junior in priority to the liens securing the obligations under the Amended Credit Facility) on the same assets securing the obligations under the Amended Credit Facility. They will bear interest at a rate of 7.5% per annum, payable in cash, with a maturity of May 31, 2022. The Second Lien Notes will be redeemable at any time, subject to the following make whole amounts: (1) if the Company prepays the Second Lien Notes prior to the third anniversary of issuance, the prepayment amount shall be at par, plus accrued interest, plus a make whole payment equal to the spread over a comparable treasury note plus 50 basis points, (2) if the Company prepays the Second Lien Notes after the third anniversary, but prior to the fifth anniversary, of issuance, the prepayment amount shall be at 105.625% of par, plus accrued interest and (3) if the Company prepays the Second Lien Notes on or after the fifth anniversary of issuance, the prepayment amount shall be at par plus accrued interest.

Building Loan – On November 20, 2015, we entered into the Building Loan, maturing on December 20, 2030. We received $11.8 million in cash, net of debt issuance costs related to the Building Loan. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments commencing on December 20, 2015. The Building Loan is collateralized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. As of December 31, 2016, our EBITDA to Net Interest Expense ratio was 3.24 to 1. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. There will be no changes to the terms of the Building Loan pursuant to the Plan.

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Cash Flow and Working Capital

Net cash provided by operating activities totaled $78.6 million during the year ended December 31, 2016 compared to $247.5 million and $401.1 million during the years ended December 31, 2015 and 2014, respectively. The decrease from 2015 to 2016 was primarily due to the decline in our hedge-effected oil, natural gas and NGL prices, the decline in natural gas and NGL production volumes, restructuring fees, rig subsidy and stacking expenses and drilling rig and offshore vessel contract termination fees, partially offset by a decline in lease operating and transportation, processing and gathering ("TP&G") expenses. The decrease from 2014 to 2015 was primarily due to the decline in oil, natural gas and NGL prices, partially offset by a decline in lease operating expenses. See Results of Operations for additional information relative to commodity prices, production and operating expense variances.

Net cash used in investing activities totaled $238.2 million during the year ended December 31, 2016, which primarily represents our investment in oil and gas properties of $238.0 million. Net cash used in investing activities totaled $321.3 million during the year ended December 31, 2015, which primarily represents our investment in oil and gas properties of $522.0 million, offset by $179.5 million of previously restricted proceeds from the sale of oil and gas properties of $22.8 million of proceeds from the sale of oil and gas properties. Net cash used in investing activities totaled $872.6 million during the year ended December 31, 2014, which primarily represents our investment in oil and gas properties of $927.2 million and our investment in fixed and other assets of $10.2 million, offset by unrestricted proceeds from the sale of oil and gas properties of $64.8 million.

Net cash provided by financing activities totaled $339.4 million during the year ended December 31, 2016, which primarily represents $477.0 million in borrowings under our bank credit facility less $135.5 million in repayments of borrowings under our bank credit facility. Net cash provided by financing activities totaled $10.2 million during the year ended December 31, 2015, which primarily represents $11.8 million of net proceeds from our Building Loan, offset by net payments for share-based compensation of approximately $3.1 million. During the year ended December 31, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility. Net cash provided by financing activities totaled $215.4 million during the year ended December 31, 2014, which primarily represents net proceeds from the sale of common stock of approximately $226.0 million, offset by net payments for share-based compensation of approximately $7.2 million and deferred financing costs of approximately $3.4 million associated with our bank credit facility.

We had working capital of $132.4 million at December 31, 2016. The $300 million of 2017 Convertible Notes due on March 1, 2017 are classified as liabilities subject to compromise at December 31, 2016 in our consolidated balance sheet. See Note 2 to the accompanying consolidated financial statements.

Capital Expenditures

During the year ended December 31, 2016, additions to oil and gas property costs of $174.0 million included $3.3 million of lease and property acquisition costs, $21.2 million of capitalized SG&A expenses (inclusive of incentive compensation) and $26.6 million of capitalized interest. These investments were financed with cash flows from operating activities and borrowings under our bank credit facility.

Share Repurchase Program

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Through December 31, 2016, 30,000 shares had been repurchased under this program at a total cost of approximately $7.1 million, or an average price of $235.70 per share (after the effectiveness of the reverse stock split of 1-for-10). No shares were repurchased during the years ended December 31, 2016, 2015 or 2014.

Hedging

See Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.

Safety Performance

Historically, we have measured our safety performance based on the total recordable incident rate ("TRIR"), which is the number of safety incidents per 200,000 man-hours worked for employees and certain contractors. For 2015, we broadened our safety performance measures, using a new factor called our Health, Safety and Environmental ("HSE") factor. The HSE factor includes not only personal safety as reflected by the TRIR, but also environmental safety, as measured by reported spills of hydrocarbons, and compliance safety, as measured by fines or penalties paid to state or federal regulatory agencies. All onshore safety incidents are reported to the Occupational Safety and Health Administration ("OSHA") and are tracked on OSHA Form

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301. All offshore safety incidents are reported to the BOEM. Our TRIR is provided to the BOEM as part of a voluntary program for safety monitoring in the GOM. The HSE factor for the years ended December 31, 2016 and 2015 and the TRIR for the year ended December 31, 2014 were as follows:



Year Ended December 31,	Safety Performance	Safety Goal
2016	0.28	0.30
2015	0.14	0.30
2014	0.00	0.50

Our safety initiative includes formal programs for observation and reporting of at-risk and safe behavior in and away from the work place, employee awards for results and observations, employee participation in training programs and internal safety audits. We have an annual cash incentive compensation plan that includes a safety component based on our annual HSE factor.

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Reorganization Items

The Debtors have incurred and will continue to incur significant costs associated with the reorganization and Chapter 11 process. These costs, which are being expensed as incurred, significantly impact the Company's results of operations. Reorganization items includes professional fees and other expenses incurred in the Chapter 11 Cases, and the write-off of the remaining unamortized deferred financing costs, premiums and discounts associated with debt classified as liabilities subject to compromise. For the year ended December 31, 2016, reorganization items totaled $10.9 million. See Note 2 to the accompanying consolidated financial statements for further details.

Results of Operations

2016 Compared to 2015. The following table sets forth certain information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and natural gas reserves. See Item 2. Properties – Oil and Natural Gas Reserves.



	Year Ended December 31,
	2016		2015		Variance			% Change
Production:
Oil (MBbls)	6,308		5,991		317			5	%
Natural gas (MMcf)	29,441		36,457		(7,016		)	(19	)%
NGLs (MBbls)	2,183		2,401		(218		)	(9	)%
Oil, natural gas and NGLs (MMcfe)	80,387		86,809		(6,422		)	(7	)%
Revenue data (in thousands): (1)
Oil revenue	$	281,246	$	416,497	$	(135,251	)	(32	)%
Natural gas revenue	64,601		83,509		(18,908		)	(23	)%
NGLs revenue	28,888		32,322		(3,434		)	(11	)%
Total oil, natural gas and NGL revenue	$	374,735	$	532,328	$	(157,593	)	(30	)%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	40.82	$	46.88	$	(6.06	)	(13	)%
Natural gas (per Mcf)	1.80		1.90		(0.10		)	(5	)%
NGLs (per Bbl)	13.23		13.46		(0.23		)	(2	)%
Oil, natural gas and NGLs (per Mcfe)	4.22		4.40		(0.18		)	(4	)%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	44.59	$	69.52	$	(24.93	)	(36	)%
Natural gas (per Mcf)	2.19		2.29		(0.10		)	(4	)%
NGLs (per Bbl)	13.23		13.46		(0.23		)	(2	)%
Oil, natural gas and NGLs (per Mcfe)	4.66		6.13		(1.47		)	(24	)%
Expenses (per Mcfe):
Lease operating expenses	$	0.99	$	1.15	$	(0.16	)	(14	)%
Transportation, processing and gathering expenses	0.35		0.68		(0.33		)	(49	)%
Salaries, general and administrative expenses (2)	0.73		0.80		(0.07		)	(9	)%
DD&A expense on oil and gas properties	2.68		3.19		(0.51		)	(16	)%
Estimated Proved Reserves at December 31:
Oil (MBbls)	23,280		30,276		(6,996		)	(23	)%
Natural gas (MMcf)	117,320		121,858		(4,538		)	(4	)%
NGLs (MBbls)	10,629		6,458		4,171			65	%
Oil, natural gas and NGLs (MMcfe)	320,773		342,260		(21,487		)	(6	)%


(1)	Includes the cash settlement of effective hedging contracts.


(2)	Excludes incentive compensation expense.

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Net Loss. For the year ended December 31, 2016, we reported a net loss totaling $590.6 million, or $105.63 per share, compared to a net loss for the year ended December 31, 2015 of $1,090.9 million, or $197.45 per share. All per share amounts are on a diluted basis.

We follow the full cost method of accounting for oil and gas properties. During the year ended December 31, 2016, we recognized write-downs of our U.S. and Canadian oil and gas properties totaling $357.4 million. During the year ended December 31, 2015, we recognized write-downs of our U.S. and Canadian oil and gas properties totaling $1,362.4 million. The write-downs did not impact our cash flows from operating activities but did increase net loss and decrease stockholders’ equity.

The variance in annual results was also due to the following components:

Production. During the year ended December 31, 2016, total production volumes decreased to 80.4 Bcfe compared to 86.8 Bcfe produced during the comparable 2015 period, representing a 7% decrease. Oil production during the year ended December 31, 2016 totaled approximately 6,308 MBbls compared to 5,991 MBbls produced during the year ended December 31, 2015. Natural gas production totaled 29.4 Bcf during the year ended December 31, 2016 compared to 36.5 Bcf produced during the comparable 2015 period. NGL production during the year ended December 31, 2016 totaled approximately 2,183 MBbls compared to 2,401 MBbls produced during the comparable 2015 period.

The decreases in natural gas and NGL production volumes during the year ended December 31, 2016 were primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016. Additionally, in April 2016, production from our deep water Amethyst well was shut in to allow for a technical evaluation. During the first week of November 2016, we initiated acid stimulation work, and on November 30, 2016, we performed a routine shut in of the well to record pressures and determined that pressure communication existed between the production tubing and production casing strings, resulting from a suspected tubing leak. Intervention operations were unsuccessful.

For the year ended December 31, 2016, total production volumes attributable to the Appalachia Properties were approximately 28.3 Bcfe, comprised of 16.1 Bcf of natural gas, 281 MBbls of oil and 1,753 MBbls of NGLs.

Prices. Prices realized during the year ended December 31, 2016 averaged $44.59 per Bbl of oil, $2.19 per Mcf of natural gas and $13.23 per Bbl of NGLs, or 24% lower, on an Mcfe basis, than 2015 average realized prices of $69.52 per Bbl of oil, $2.29 per Mcf of natural gas and $13.46 per Bbl of NGLs. All unit pricing amounts include the cash settlement of effective hedging contracts.

We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. During the year ended December 31, 2016, effective hedging transactions increased our average realized natural gas price by $0.39 per Mcf and increased our average realized oil price by $3.77 per Bbl. During the year ended December 31, 2015, effective hedging transactions increased our average realized natural gas price by $0.39 per Mcf and increased our average realized oil price by $22.64 per Bbl.

Revenue. Oil, natural gas and NGL revenue decreased 30% to $374.7 million for the year ended December 31, 2016 from $532.3 million for the year ended December 31, 2015. Total revenue for the year ended December 31, 2016 was lower primarily due to a 7% decrease in production volumes and a 24% decrease in average realized prices on an equivalent basis from the comparable period of 2015. For the year ended December 31, 2016, total oil, natural gas and NGL revenue attributable to the Appalachia Properties was $56.7 million.

Derivative Income/Expense. Net derivative expense for the year ended December 31, 2016 totaled $0.8 million, comprised of $0.7 million of income from cash settlements and $1.5 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the year ended December 31, 2015, net derivative income totaled $8.0 million, comprised of $24.4 million of income from cash settlements and $16.4 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments.

Expenses. Lease operating expenses for the years ended December 31, 2016 and 2015 totaled $79.7 million and $100.1 million, respectively. On a unit of production basis, lease operating expenses were $0.99 per Mcfe and $1.15 per Mcfe for the years ended December 31, 2016 and 2015, respectively. The decrease in lease operating expenses in 2016 was primarily attributable to service cost reductions, the implementation of cost-savings measures, operating efficiencies and the shut-in of production at our Mary field from September 2015 until late June 2016. For the year ended December 31, 2016, lease operating expenses attributable to the Appalachia Properties were $11.6 million.

TP&G expenses for the year ended December 31, 2016 totaled $27.8 million, which included a $7.9 million recoupment of prior period expenses against Federal royalties, compared to $58.8 million for the year ended December 31, 2015, or $0.35 per

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Mcfe and $0.68 per Mcfe, respectively. The decrease in TP&G expenses during the year ended December 31, 2016 was primarily attributable to the shut-in of production at our Mary field from September 2015 until late June 2016. For the year ended December 31, 2016, TP&G expenses attributable to the Appalachia Properties were $28.1 million.

Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the year ended December 31, 2016 totaled $215.7 million, or $2.68 per Mcfe, compared to DD&A expense of $277.1 million, or $3.19 per Mcfe, for the year ended December 31, 2015. The decrease in DD&A from 2015 was primarily due to the ceiling test write-downs of our oil and gas properties.

Other operational expenses for the years ended December 31, 2016 and 2015 totaled $55.5 million and $2.4 million, respectively. Included in other operational expenses for the year ended December 31, 2016 are $9.9 million in charges related to the terminations of an Appalachian drilling rig contract and contracts with two GOM vendors, a $20.0 million charge related to the termination of our deep water drilling rig contract with Ensco in June 2016, approximately $17.7 million of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, the Appalachian drilling rig and the platform rig at Pompano, and a $6.1 million cumulative foreign currency translation loss on the substantial liquidation of our foreign subsidiary, Stone Energy Canada ULC, which was reclassified from accumulated other comprehensive income.

For the years ended December 31, 2016 and 2015, SG&A expenses (exclusive of incentive compensation) totaled $58.9 million and $69.4 million, respectively. On a unit of production basis, SG&A expenses were $0.73 per Mcfe and $0.80 per Mcfe for the years ended December 31, 2016 and 2015, respectively. The decrease in SG&A expenses in 2016 was primarily attributable to staff and other cost reductions. SG&A expenses for the year ended December 31, 2015 included $2.1 million of lease termination charges associated with the early termination of an office lease.

For the years ended December 31, 2016 and 2015, incentive compensation expense totaled $13.5 million and $2.2 million, respectively. The 2016 incentive compensation cash bonuses are calculated based on the achievement of certain strategic objectives for each quarter of 2016. Portions of the 2016 incentive cash bonuses replaced amounts previously awarded to employees as stock-based compensation, reflected in SG&A expenses, resulting in higher incentive compensation expense in the year ended December 31, 2016 as compared to the year ended December 31, 2015.

For the year ended December 31, 2016, restructuring fees totaled $29.6 million. These fees, incurred prior to the filing of the Bankruptcy Petitions, related to expenses supporting our restructuring effort including legal and financial advisory costs for Stone, our bank group and our noteholders.

Interest expense for the year ended December 31, 2016 totaled $64.5 million, net of $26.6 million of capitalized interest, compared to interest expense of $43.9 million, net of $41.3 million of capitalized interest, for the year ended December 31, 2015. The increase in interest expense was primarily the result of interest expense associated with the increased borrowings under our bank credit facility and a decrease in the amount of interest capitalized to oil and gas properties.

For the years ended December 31, 2016 and 2015, we recorded an income tax provision (benefit) of $7.4 million and ($316.4) million, respectively. The income tax benefit recorded for the year ended December 31, 2015 was a result of our loss before income taxes attributable to the ceiling test write-downs of our oil and gas properties. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined in the third quarter of 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. The change in the valuation allowance was recorded as an adjustment to income tax expense.

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2015 Compared to 2014. The following table sets forth certain information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and natural gas reserves. See Item 2. Properties – Oil and Natural Gas Reserves.



	Year Ended December 31,
	2015		2014		Variance			% Change
Production:
Oil (MBbls)	5,991		5,568		423			8	%
Natural gas (MMcf)	36,457		47,426		(10,969		)	(23	)%
NGLs (MBbls)	2,401		2,114		287			14	%
Oil, natural gas and NGLs (MMcfe)	86,809		93,518		(6,709		)	(7	)%
Revenue data (in thousands): (1)
Oil revenue	$	416,497	$	516,104	$	(99,607	)	(19	)%
Natural gas revenue	83,509		166,494		(82,985		)	(50	)%
NGL revenue	32,322		85,642		(53,320		)	(62	)%
Total oil, natural gas and NGL revenue	$	532,328	$	768,240	$	(235,912	)	(31	)%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	46.88	$	91.27	$	(44.39	)	(49	)%
Natural gas (per Mcf)	1.90		3.67		(1.77		)	(48	)%
NGLs (per Bbl)	13.46		40.51		(27.05		)	(67	)%
Oil, natural gas and NGLs (per Mcfe)	4.40		8.21		(3.81		)	(46	)%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	69.52	$	92.69	$	(23.17	)	(25	)%
Natural gas (per Mcf)	2.29		3.51		(1.22		)	(35	)%
NGLs (per Bbl)	13.46		40.51		(27.05		)	(67	)%
Oil, natural gas and NGLs (per Mcfe)	6.13		8.21		(2.08		)	(25	)%
Expenses (per Mcfe):
Lease operating expenses	$	1.15	$	1.89	$	(0.74	)	(39	)%
Transportation, processing and gathering expenses	0.68		0.69		(0.01		)	(1	)%
Salaries, general and administrative expenses (2)	0.80		0.71		0.09			13	%
DD&A expense on oil and gas properties	3.19		3.59		(0.40		)	(11	)%
Estimated Proved Reserves at December 31:
Oil (MBbls)	30,276		42,397		(12,121		)	(29	)%
Natural gas (MMcf)	121,858		493,843		(371,985		)	(75	)%
NGLs (MBbls)	6,458		27,817		(21,359		)	(77	)%
Oil, natural gas and NGLs (MMcfe)	342,260		915,124		(572,864		)	(63	)%


(1)	Includes the cash settlement of effective hedging contracts.


(2)	Excludes incentive compensation expense.

Net Loss. For the year ended December 31, 2015, we reported a net loss totaling $1,090.9 million, or $197.45 per share, compared to a net loss for the year ended December 31, 2014 of $189.5 million, or $35.95 per share. All per share amounts are on a diluted basis.

We follow the full cost method of accounting for oil and gas properties. During the year ended December 31, 2015, we recognized write-downs of our U.S. oil and gas properties totaling $1,362.4 million. During the year ended December 31, 2014, we recognized write-downs of our U.S. oil and gas properties totaling $351.2 million. The write-downs did not impact our cash flows from operating activities but did increase net loss and decrease stockholders’ equity.

The variance in annual results was due to the following components:

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Production. During the year ended December 31, 2015, total production volumes decreased to 86.8 Bcfe compared to 93.5 Bcfe produced during the comparable 2014 period, representing a 7% decrease. Oil production during the year ended December 31, 2015 totaled approximately 5,991 MBbls compared to 5,568 MBbls produced during the year ended December 31, 2014. Natural gas production totaled 36.5 Bcf during the year ended December 31, 2015 compared to 47.4 Bcf produced during the comparable 2014 period. NGL production during the year ended December 31, 2015 totaled approximately 2,401 MBbls compared to 2,114 MBbls produced during the comparable 2014 period.

During the three months ended June 30, 2015, we realized increases to our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units. Although we recognized approximately 1.7 Bcfe of incremental production volumes in 2015 associated with the increased interests, net operating income for the affected wells was only minimally impacted due to depressed commodity prices. The increase in oil volumes during the year ended December 31, 2015 was attributable to production from our deep water Cardona wells, which began producing late in the fourth quarter of 2014. These increases in production were partially offset by decreases in production resulting from the divestitures of certain of our non-core GOM conventional shelf properties during 2014. Production volumes for the year ended December 31, 2015 were also negatively impacted by the September 1, 2015 shut-in of the Mary field in Appalachia.

Prices. Prices realized during the year ended December 31, 2015 averaged $69.52 per Bbl of oil, $2.29 per Mcf of natural gas and $13.46 per Bbl of NGLs, or 25% lower, on an Mcfe basis, than 2014 average realized prices of $92.69 per Bbl of oil, $3.51 per Mcf of natural gas and $40.51 per Bbl of NGLs. All unit pricing amounts include the cash settlement of effective hedging contracts.

We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. During the year ended December 31, 2015, effective hedging transactions increased our average realized natural gas price by $0.39 per Mcf and increased our average realized oil price by $22.64 per Bbl. During the year ended December 31, 2014, effective hedging transactions decreased our average realized natural gas price by $0.16 per Mcf and increased our average realized oil price by $1.42 per Bbl.

Revenue. Oil, natural gas and NGL revenue decreased 31% to $532.3 million for the year ended December 31, 2015 from $768.2 million for the year ended December 31, 2014. Total revenue for the year ended December 31, 2015 was lower partially due to a 25% decrease in average realized prices. The decrease was also attributable to the divestiture of certain non-core GOM conventional shelf properties during 2014.

Derivative Income/Expense. Net derivative income for the year ended December 31, 2015 totaled $8.0 million, comprised of $24.4 million of income from cash settlements and $16.4 million of non-cash expense resulting from changes in the fair value of unsettled derivative instruments. For the year ended December 31, 2014, net derivative income totaled $19.4 million, comprised of $1.4 million of income from cash settlements and $18.0 million of non-cash income resulting from changes in the fair value of unsettled derivative instruments.

Expenses. Lease operating expenses for the years ended December 31, 2015 and 2014 totaled $100.1 million and $176.5 million, respectively. On a unit of production basis, lease operating expenses were $1.15 per Mcfe and $1.89 per Mcfe for the years ended December 31, 2015 and 2014, respectively. The decrease in lease operating expenses in 2015 was primarily attributable to the divestitures of certain non-core GOM conventional shelf properties during 2014 as well as service cost reductions and operating efficiencies.

TP&G expenses for the years ended December 31, 2015 and 2014 totaled $58.8 million and $65.0 million, respectively, or $0.68 per Mcfe and $0.69 per Mcfe, respectively. The decrease was primarily attributable to the shut-in of production at our Mary field on September 1, 2015. The expenses for the year ended December 31, 2015 included a $3.2 million accrual for a potential liability associated with an ongoing regulatory examination relating to processing fees for our GOM production.

DD&A expense on oil and gas properties for the year ended December 31, 2015 totaled $277.1 million, or $3.19 per Mcfe, compared to DD&A expense of $336.0 million, or $3.59 per Mcfe, for the year ended December 31, 2014. The decrease in DD&A from 2014 was primarily due to the ceiling test write-downs of our oil and gas properties.

For the years ended December 31, 2015 and 2014, SG&A expenses (exclusive of incentive compensation) totaled $69.4 million and $66.5 million, respectively. The increase in SG&A expenses in 2015 related primarily to $3.7 million in severance payments made in conjunction with a reduction of our workforce and $2.1 million of lease termination charges associated with the early termination of an office lease.

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For the years ended December 31, 2015 and 2014, incentive compensation expense totaled $2.2 million and $10.4 million, respectively. These amounts related to incentive compensation bonuses calculated based on the achievement of certain strategic objectives for each fiscal year.

Interest expense for the year ended December 31, 2015 totaled $43.9 million, net of $41.3 million of capitalized interest, compared to interest expense of $38.9 million, net of $45.7 million of capitalized interest, for the year ended December 31, 2014. The increase in interest expense was primarily the result of a decrease in the amount of interest capitalized to oil and gas properties.

For the years ended December 31, 2015 and 2014, we recorded income tax benefits of $316.4 million and $102.0 million, respectively. The income tax benefits recorded in 2015 and 2014 were a result of our losses before income taxes attributable to the ceiling test write-downs. The income tax benefit for the year ended December 31, 2015 was partially offset by the establishment of a valuation allowance against a portion of our deferred tax assets. The 2015 current income tax benefit of $44.1 million represented expected income tax refunds from the carryback of net operating losses to prior tax years.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Contractual Obligations and Other Commitments

The following table summarizes our significant contractual obligations and commitments, other than derivative contracts, by maturity as of December 31, 2016 (in thousands). The table does not reflect any potential changes to our contractual obligations and other commitments that may result from the Chapter 11 process and activities contemplated by the Plan. For example, the Plan contemplates that approximately $1.1 billion of our debt obligations reflected in the table below would be cancelled and exchanged for equity. Additionally, other contractual obligations or commitments may be amended, including our bank credit facility. The table below does not include contractual interest payment obligations that would have been required for the original term of the debt instruments that are classified as liabilities subject to compromise on our consolidated balance sheet at December 31, 2016. The Bankruptcy Petitions constituted an event of default that accelerated the Company's obligations under all of its outstanding debt instruments, resulting in the principal and interest due thereunder immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Bankruptcy Petitions. See note 2 to the consolidated financial statements for additional information on the bankruptcy proceedings.



	Payments Due By Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Contractual Obligations and Commitments:
1 3⁄4% Senior Convertible Notes due 2017	$	300,000	$	300,000	$	—	$	—	$	—
7 1⁄2% Senior Notes due 2022	775,000		—		—		—		775,000
Revolving Credit Facility	341,500		—		341,500		—		—
4.20% Building Loan	11,379		408		868		944		9,159
Interest and commitment fees (1)	32,092		11,456		17,320		811		2,505
Asset retirement obligations including accretion	664,674		127,260		70,349		36,176		430,889
Rig commitments (2)	12,650		12,650		—		—		—
Seismic data commitments	15,380		7,690		7,690		—		—
Operating lease obligations	2,508		877		1,065		566		—
Total Contractual Obligations and Commitments	$	2,155,183	$	460,341	$	438,792	$	38,497	$	1,217,553


(1)	Includes interest payable on the bank credit facility and Building Loan. Assumes 0.50% fee on unused commitments under the bank credit facility.


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

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Forward-Looking Statements

Certain of the statements set forth under this item and elsewhere in this Form 10-K are forward-looking and are based upon assumptions and anticipated results that are subject to numerous risks and uncertainties. See Item 1. Business — Forward-Looking Statements and Item 1A. Risk Factors.

Accounting Matters and Critical Accounting Estimates

Presentation. Subsequent to filing the Bankruptcy Petitions, we have prepared our consolidated financial statements in accordance with Accounting Standards Codification ("ASC") 852, "Reorganizations". ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 Cases, and the write-off of remaining unamortized deferred financing costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. These liabilities are reported at the amounts the Company expects will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

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

As of December 31, 2016 and 2015, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.

Asset Retirement Obligations. We are required to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The guidance regarding asset retirement obligations requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. Our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

Full Cost Method. We follow the full cost method of accounting for our oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of acquiring and finding oil and gas are capitalized. Unevaluated property costs are excluded from the amortization base until we have made a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to proved oil and gas properties and thereby subject to DD&A. Sales of oil and gas properties are accounted for as adjustments to net proved oil and gas properties with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

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

We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. We also capitalize the portion of SG&A expenses that are attributable to our acquisition, exploration and development activities.

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by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360.

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

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

Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires us 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 revenue and expenses during the reporting period. Actual results could differ from those estimates. Our most significant estimates are:


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


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


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


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


•	effectiveness and estimated fair value of derivative positions;


•	classification of unevaluated property costs;


•	capitalized general and administrative costs and interest;


•	estimates of fair value in business combinations;


•	current and deferred income taxes;


•	liabilities subject to compromise vs. not subject to compromise; and


•	contingencies.

For a more complete discussion of our accounting policies and procedures see our “Notes to Consolidated Financial Statements” beginning on page F-8.

Recent Accounting Developments

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

In August 2014, the FASB issued ASU 2014-15, "Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)". The guidance requires management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management is required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it concludes its plans alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 became effective for us on December 15, 2016. The standard impacted our disclosures but had no effect on our financial position, results of operations or cash flows.

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In November 2015, the FASB issued ASU 2015-17, "Balance Sheet Classification of Deferred Taxes" to simplify the presentation of deferred income taxes. The guidance allows for the presentation of all deferred tax assets and liabilities, along with any related valuation allowance, to be classified as noncurrent on the balance sheet. We early adopted ASU 2015-17, on a retrospective basis, which affected our disclosures of deferred tax assets and liabilities as of December 31, 2016 and 2015, but had no effect on our financial position, results of operations or cash flows.

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

In March 2016, the FASB issued ASU 2016-09, "Compensation – Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 is effective for public entities for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early adoption is permitted for any entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in ASU 2016-09 in the same period. We are currently evaluating the effect that this new standard may have on our financial statements, but we do not anticipate the implementation of this new standard will have a material effect.

ITEM 7A. 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 year ended December 31, 2016, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $26.4 million impact on our revenues. Excluding the effects of hedging contracts, a 10% fluctuation in realized oil and natural gas prices would have had an approximate $33.9 million impact on our revenues. In order to manage our exposure to oil and natural gas price declines, we enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.

Our hedging policy currently provides that not more than 60% of our estimated production quantities can be hedged for any given year without the consent of the board of directors. We believe that our hedging positions as of February 23, 2017 have hedged approximately 7% of our estimated 2017 production from estimated proved reserves and 6% of our estimated 2018 production from estimated proved reserves. We continue to monitor the market place for additional hedges we deem acceptable. Pursuant to requirements under the Plan, we expect to hedge approximately 50% of our estimated production from estimated proved producing reserves for each of 2017 and 2018. See Note 7 – Derivative Instruments and Hedging Activities to the accompanying consolidated financial statements included in this Annual Report on Form 10-K for a detailed discussion of hedges in place to manage our exposure to oil and natural gas price declines.

Interest Rate Risk. We had total debt outstanding of $1,427.8 million at December 31, 2016, of which $1,086.3 million, or 76%, bears interest at fixed rates. The $1,086.3 million of fixed-rate debt is comprised of $300 million face value of the 2017 Convertible Notes, $775 million of the 2022 Notes and $11.3 million of the Building Loan. At December 31, 2016, the remaining $341.5 million of our outstanding debt bears interest at an adjustable rate and consists of borrowings outstanding under our bank credit facility. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources. Borrowings under our bank credit facility may subject us to increased sensitivity to interest rate movements. At February 23, 2017, we had $341.5 million of borrowings outstanding under our bank credit facility. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. At December 31, 2016, the weighted average interest rate under our bank credit facility was approximately 3.2% per annum.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information concerning this Item begins on Page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There have been no disagreements with our independent registered public accounting firm on our accounting or financial reporting that would require our independent registered public accounting firm to qualify or disclaim its report on our financial statements or otherwise require disclosure in this Form 10-K.

ITEM 9A. CONTROLS AND PROCEDURES

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-K. 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 SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2016 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 December 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by the Exchange Act. Under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016. In making this assessment, we used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (2013 framework). Based on our evaluation, we have concluded that our internal controls over financial reporting were effective as of December 31, 2016. Ernst and Young LLP, an independent public accounting firm, has issued its report on the Company’s internal control over financial reporting as of December 31, 2016.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

We have audited Stone Energy Corporation’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Stone Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Stone Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Stone Energy Corporation as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), cash flows and changes in stockholders’ equity for each of the three years in the period ended December 31, 2016 and our report dated February 23, 2017 expressed an unqualified opinion thereon that included an explanatory paragraph regarding Stone Energy Corporation's ability to continue as a going concern.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 23, 2017

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ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Identification of Directors

Set forth below is biographical information regarding each of our current directors. There are no family relationships between any of our directors and executive officers. In addition, there are no arrangements or understandings between any of our executive officers or directors and any other person pursuant to which any person was selected as a director or an executive officer, respectively.

The Plan filed by the Company with the Bankruptcy Court provides that upon emergence from bankruptcy, the term of each of the current board members will expire, and the post-emergence Company's new board will consist of seven directors, including six new directors appointed by the Noteholders, and our chief executive officer, David H. Welch.

George R. Christmas, age 77, Director since 2003, Chairman of the Compensation Committee and Member of the Nominating & Governance Committee. Retired Lt. General George R. Christmas retired in 2011 as President and Chief Executive Officer of the Marine Corps Heritage Foundation, which directly supports the historical programs of the Marine Corps, preserves the history, traditions and culture of the Marine Corps, and educates Americans in its virtues. Retired Lt. Gen. Christmas graduated from the University of Pennsylvania with a bachelor of arts degree and then from Shippensburg University with a master of public administration degree. He served in the U.S. Marine Corps from 1962 to 1996, originally commissioned as a second lieutenant and rising to Brigadier General in 1988, Major General in 1991, and Lieutenant General in 1993 as Commanding General, I Marine Expeditionary Force, Camp Pendleton, California. Lt. General Christmas’s personal decorations and medals include the Navy Cross, Defense Distinguished Service Medal, Navy Distinguished Service Medal, Defense Superior Service Medal, Purple Heart, Meritorious Service Medal and three gold stars in lieu of consecutive awards, the Army Commendation Medal, and the Vietnamese Cross of Gallantry with palm. He previously served as a consultant or advisor to various entities, including Wexford Group International, Northrup Gruman Space & Mission Systems Corporation, Marine Corps Heritage Foundation, RAND Corporation and HARRIS Corporation. Retired Lt. General Christmas presently serves as an advisor to the Marine Corps Heritage Foundation; as Member, Advisory Board, to the Florence & Robert A. Rosen Family Wellness Center for Law Enforcement and Military; as Chairman, Board of Directors, for Center House Association; as Marine Corps Senior Advisor for the Department of Defense Commemoration of the 50th Anniversary of the Vietnam War; as Witness to the War Advisory Board; as Member of the Stafford County Virginia Armed Services Memorial Commission; and as Trustee of the Stafford Hospital Foundation.

B.J. Duplantis, age 77, Director since 1993, Chairman of the Nominating & Governance Committee and Member of the Compensation and Reserve Committees. Mr. Duplantis is a senior partner with the law firm of Gordon, Arata, McCollam, Duplantis & Eagan, having joined the firm in 1982, with a practice focused on the oil and gas industry. Prior to joining the law firm, Mr. Duplantis served in the legal department of The Superior Oil Company from 1979 to 1982 and previously was employed by Shell Oil Company, where he served in various engineering and management capacities over 10 years in Louisiana, Texas, California and New York, and also as a member of its legal department from 1971 to 1978. Mr. Duplantis graduated from Louisiana State University with a bachelor of science degree in petroleum chemical engineering and from Loyola University with a Juris Doctor degree. In addition to his several professional affiliations, Mr. Duplantis has served on the Louisiana State Office of Conservation Intrastate Pipelines Ad Hoc Committee, the Louisiana State Office of Conservation Committee on Revision of Rules of Procedure, and the Advisory Committee for the Louisiana State Commissioner’s Office of Conservation, and is a former board member of Holy Cross College, New Orleans, Louisiana.

Peter D. Kinnear, age 70, Director since 2008, Member of the Audit, Compensation and Nominating & Governance Committees. Mr. Kinnear held numerous management, operations and marketing roles with FMC Technologies, Inc. and FMC Corporation, both leading providers of technology services to the energy industry, starting in 1971 and retiring from FMC Technologies, Inc. in 2011. Mr. Kinnear served as Chief Executive Officer from March 2007 through February 2011 of FMC Technologies, Inc., and previously as President from March 2006 through April 2010, and Chief Operating Officer from March 2006 through March 2007. Mr. Kinnear received a bachelor’s degree in chemical engineering from Vanderbilt University and an MBA from the University of Chicago. Mr. Kinnear presently serves on the board of directors of Superior Energy Services, Inc. (member of the audit and corporate governance committees). In addition to serving as trustee or director of various non-public entities, including The Petroleum Equipment Suppliers Association, the Business Council, and Spindletop International, Mr.

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Kinnear previously served on the board of directors of Tronox Incorporated from November 2005 to December 2010, and as FMC Technologies, Inc.’s Chairman of the Board from October 2008 through October 2011.

David T. Lawrence, age 61, Director since 2013, Member of the Audit, Nominating & Governance, Reserves and Special Committees. Mr. Lawrence has extensive global experience across the upstream energy business. He currently is Chairman and CEO of Lawrence Energy Group LLC. He served as Executive Vice President Exploration and Commercial for Shell Upstream Americas and Functional Head of Global Exploration for Shell worldwide from June 2009 until retiring from this position in April 2013. His responsibilities included exploration, acquisitions, divestments, new business development, LNG, Gas to Liquids and wind energy in the Americas. Prior roles included Executive Vice President Global Exploration and Executive Vice President Investor Relations for Royal Dutch Shell based in The Hague and London, respectively, and Vice President Exploration and Development for Shell Exploration and Production Company in the United States. In his 29 years with Shell, Mr. Lawrence conducted business in more than 40 countries around the globe. Mr. Lawrence currently serves as a Trustee Associate of the American Association of Petroleum Geologists Foundation, and he has served as Chairman of the Yale Climate and Energy Institute External Advisory Board and on the National Ocean Industry Association as Membership Chair and as a past commissioner on the Aspen Institute Commission on Arctic Climate Change. He was a member of the American Petroleum Institute Upstream Committee, where he helped lead efforts to establish the Center for Offshore Safety and was the Chairman of the European Association of Geologists and Engineers (EAGE) Annual Meeting in Amsterdam in 2008. Mr. Lawrence is the author of numerous technical and business articles, is a recipient of the Meritorious Service Award from the American Petroleum Institute, and received the Wallace Pratt Memorial Award for best paper in the American Association of Petroleum Geologists bulletin. Mr. Lawrence received his Ph.D. in Geology and Geophysics from Yale University in 1984 and his B.A. in Geology from Lawrence University in 1977.

Robert S. Murley, age 67, Director since 2011, Member of the Audit, Compensation, Nominating & Governance and Special Committees. Mr. Murley is a Senior Advisor to Credit Suisse, LLC, having been employed by Credit Suisse and its predecessors from 1975 to April 2012. In 2005, he was appointed Chairman of Investment Banking in the Americas, serving in that position until April 2012. Prior to that time, Mr. Murley headed the Global Industrial and Services Group within the Investment Banking Division, as well as the Chicago investment banking office. He was named a Managing Director in 1984 and appointed a Vice Chairman in 1998. Mr. Murley received a bachelor of arts degree from Princeton University, an MBA from the UCLA Anderson School of Management and a master of science degree in International Economics from the London School of Economics. Mr. Murley has been a director of Apollo Education Group since June 2011 (Chairman of the audit and finance committees, and member of the nominating and governance committee), a director of Health Insurance Innovations since November 2013 and Brown Advisory Group since January 2016. He also serves as an Emeritus Trustee of Princeton University, is a Trustee and past Chairman of the Board of the Educational Testing Service in Princeton, New Jersey, is Vice Chairman of the Board of the Ann & Robert Lurie Children’s Hospital of Chicago, is Chairman of the Board of Advisors of the UCLA Anderson School of Management and is a Trustee of the Museum of Science & Industry in Chicago, Illinois.

Richard A. Pattarozzi, age 73, Director since 2000, Lead Independent Director, Member of the Nominating & Governance and Reserves Committees. Mr. Pattarozzi served as Vice President of Shell Oil Company from March 1999 until his retirement in January 2000, having worked for Shell Oil Company for over 33 years, from 1966 to 2000, in the United States, both onshore and in the Gulf of Mexico. He also served as President and Chief Executive Officer for both Shell Deepwater Development, Inc. and Shell Deepwater Production, Inc. from 1995 until 1999, and previously was appointed General Manager of Shell’s Deepwater Production Division in April 1991 and General Manager of Shell’s Deepwater Exploration and Production Division in October 1991. Mr. Pattarozzi graduated from the University of Illinois with a civil engineering degree. Mr. Pattarozzi presently serves on the board of directors of FMC Technologies, Inc., Lead Director and (member of the compensation committee and Chair of the nominating and governance committee) and Tidewater Inc. (“Tidewater”) (as independent Chairman of the Board and a member of the compensation and nominating and governance committees), both of which are public companies. Mr. Pattarozzi previously served on the boards of Superior Energy Services, Inc. and Global Industries, Ltd., which merged with Technip in December 2011. Mr. Pattarozzi also serves on the board of trustees of the U.S. Army War College Foundation and is a past Trustee of the National World War II Museum, Inc. and past Chairman of the Offshore Energy Center and also of the United Way in New Orleans, Louisiana.

Donald E. Powell, age 75, Director since 2008, Member of the Audit, Nominating & Governance and Special Committees. Mr. Powell served as the Federal Coordinator of Gulf Coast Rebuilding from November 2005 until March 2008, and he received the Presidential Citizens Medal in 2008 from President George W. Bush. Mr. Powell was the 18th Chairman of the Federal Deposit Insurance Corporation, where he served from August 2001 until November 2005. Mr. Powell previously served as President and Chief Executive Officer of the First National Bank of Amarillo, where he started his banking career in 1971. Mr. Powell graduated from West Texas State University with a Bachelor of Science degree in economics and is a graduate of The Southwestern Graduate School of Banking at Southern Methodist University. Mr. Powell presently serves on the board of directors of T.D. Williamson, a privately held company. Mr. Powell previously served as a director of QR Energy, LP (member of the audit and compensation

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committees and Chairman of the conflicts committee prior to resigning in connection with the acquisition of QR Energy, LP by Breitburn Energy Partners LP in November 2014) and as a director of Bank of America Corporation and Merrill Lynch International (United Kingdom) (retiring in May 2013 from both). He has also served on the boards of several non-public, civic and charitable organizations, including as chairman of the Board of Regents of the Texas A&M University System, Advisory Board Member of the George Bush School of Government and Public Service and Chairman of the Amarillo Chamber of Commerce, the City of Amarillo Housing Board and the High Plains Baptist Hospital and Harrington Regional Medical Center in Amarillo, Texas.

Kay G. Priestly, age 61, Director since 2006, Chairman of the Audit Committee, Member of the Nominating & Governance, Reserves and Special Committees. Ms. Priestly was formerly the Chief Executive Officer and a director of Turquoise Hill Resources Ltd., an international mining company focused on copper, gold and coal in the Asia Pacific region, retiring therefrom as of December 31, 2014. From 2008 until her appointment as CEO of Turquoise Hill in 2012, she was Chief Financial Officer of Rio Tinto Copper (a division of the Rio Tinto Group - Rio Tinto plc and Rio Tinto Limited). From 2006 to 2008, she was Vice President, Finance and Chief Financial Officer of Rio Tinto’s Kennecott Utah Copper operations. Ms. Priestly served as Vice President, Risk Management and General Auditor for Entergy Corporation, an integrated energy company engaged primarily in electric power production and retail distribution operations, from 2004 to 2006. Ms. Priestly previously spent over 24 years with global professional services firm Arthur Andersen, where she provided tax, consulting and mergers & acquisitions services to global companies across many industries, including energy, mining, manufacturing and services. While at Andersen, she was a member of the global energy team, served as managing partner of the New Orleans office from 1997 to 2000, and was a member of Andersen’s global executive team from 2001 to 2002 where she had overall responsibility for the firm’s human resources strategy. Ms. Priestly also serves on the board of directors for New Gold, Inc. and for Technip FMC. She formerly served as Chairman of the board of directors of SouthGobi Resources Ltd., from September 2012 through December 2014, retiring therefrom as of December 31, 2014, and formerly served as a director of Palabora Mining Company Limited from January 2009 through May 2010.

Phyllis M. Taylor, age 75, Director since 2012, Chairman of the Reserves Committee, Member of the Compensation and Nominating & Governance Committees. Ms. Taylor is the Chairman and Chief Executive Officer of Taylor Energy Company LLC. Ms. Taylor is a graduate of Tulane University School of Law in New Orleans, and she served as a law clerk for the Supreme Court of Louisiana and subsequently served as in-house counsel for private energy companies. Ms. Taylor also serves as Chairman and President of the Patrick F. Taylor Foundation and on the Iberia Bank Advisory Board. Ms. Taylor is involved in numerous civic activities, including serving on the New Orleans Business Council, Catholic Leadership Institute National Advisory Board and the Tulane University Board of Trustees.

David H. Welch, age 68, Director since 2004, Chairman of the Board. Mr. Welch has served as the President and Chief Executive Officer of Stone since April 2004 and has served as Chairman of the Board since May 2012. Prior to joining our company in 2004, he worked for BP Amoco or its predecessors for 26 years, where his final role was Senior Vice President, BP America Inc. Mr. Welch has an engineering degree from Louisiana State University and a doctoral degree in engineering and economics from Tulane University. He has completed the Harvard Business School advanced management program and executive development programs at Stanford Business School and at Cambridge University. Mr. Welch serves as a director of Iberia Bank (member of the Investment Committee, Enterprise Risk Committee and Trust Oversight Committee). Mr. Welch has served as Chairman of the Offshore Energy Center, Chairman of the Greater Lafayette Chamber of Commerce and 2011 Chairman of the United Way in Acadiana. He currently serves as Vice Chairman of the National Ocean Industries Association, a trustee of The Nature Conservancy of Louisiana, a director of the Offshore Energy Center, a director of Louisiana Association of Business and Industry, a director of the Upper Lafayette Economic Development Foundation, Acadiana Symphony Orchestra and on the Lafayette Central Park board.

Identification of Executive Officers

The following table sets forth information regarding the names, ages (as of February 23, 2017) and positions held by each of our executive officers, followed by biographies describing the business experience of our executive officers for at least the past five years. Our executive officers serve at the discretion of our Board.

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Name	Age	Position
David H. Welch	68	Chairman of the Board, President and Chief Executive Officer
Kenneth H. Beer	59	Executive Vice President and Chief Financial Officer
Lisa S. Jaubert	61	Senior Vice President, General Counsel and Secretary
John J. Leonard	57	Senior Vice President - Exploration and Business Development
E. J. Louviere	68	Senior Vice President - Land
Thomas L. Messonnier	55	Vice President - Planning, Marketing & Midstream
Keith A. Seilhan	50	Senior Vice President - Gulf of Mexico
Richard L. Toothman, Jr.	53	Senior Vice President - Appalachia
Florence M. Ziegler	56	Senior Vice President - Human Resources, Communications and Administration

For Mr. Welch’s biographical information, see “Identification of Directors” above.

Kenneth H. Beer was named Executive Vice President and Chief Financial Officer in January 2011. Previously, he served as Senior Vice President and Chief Financial Officer since August 2005. Prior to joining Stone, he served as a director of research and a senior energy analyst at the investment banking firm of Johnson Rice & Company. Prior to joining Johnson Rice & Company in 1992, he was an energy analyst and investment banker at Howard Weil Incorporated.

Lisa S. Jaubert was named Senior Vice President, General Counsel and Secretary in May 2013. She previously served as Assistant General Counsel since joining Stone in July 2012. Prior to joining Stone, she worked as Counsel with Latham & Watkins, LLP where she was a specialist in M&A, finance and other energy related transactions. Mrs. Jaubert also served over five years as Assistant General Counsel and Assistant Corporate Secretary for Mariner Energy, was a founding shareholder of Schully Roberts Slattery Jaubert & Marino PLC, and also served as an outsourced general counsel for many smaller E&P companies and was partner or associate in two other energy law firms.

John J. Leonard was named Senior Vice President-Exploration and Business Development in January 2015 and Senior Vice President-Exploration in December 2014. He previously was appointed Vice President-Exploration in January 2014, General Manager of Deepwater Development from February 2013 through January 2014, Director of Reservoir Engineering from January 2012 through February 2013, Asset Manager Conventional Shelf from July 2011 through January 2012, Asset Manager GOM Shelf East from January 2010 through July 2011, Eastern GOM Asset Manager from January 2007 through January 2010, Chief Reservoir Engineer from February 2006 through January 2007, and also Reservoir Engineer from August 2005 through February 2006. Prior to joining Stone in August 2005, he was employed by Object Reservoir as a Project Manager and Service Engineer, by Expro Americas as an Engineering Manager, and by Pro Tech and Production Wireline Services as an Engineering Manager.

E. J. Louviere was named Senior Vice President-Land in April 2004. Previously, he served as Vice President-Land since June 1995. He has been employed by Stone since its inception in 1993.

Thomas L. Messonnier was named Vice President-Planning, Marketing & Midstream in May 2015. He previously served as Director of Strategic Planning from January 2009 through May 2015, Exploitation Manager for the Gulf of Mexico and Rockies from February 2006 through January 2009, Reserves Engineering Manager from April 2005 through February 2006, and as a Reservoir Engineer from June 2004 through January 2005. Prior to joining Stone, he was employed by ARCO Oil and Gas Company where he served in various engineering functions from June 1985 through January 1997 and as President of T&T Pipeline and Construction Company from January 1997 until joining Stone in June of 2004.

Keith A. Seilhan was named Senior Vice President-Gulf of Mexico in January 2015 and Vice President-Deep Water in February 2013. He previously served as Deep Water Projects Manager since joining Stone in July 2012. Prior to joining Stone, Mr. Seilhan filled various senior leadership roles for Amoco and BP over his 21 year career with them. In his final year with BP, he filled the role as BP’s Incident Commander on the Deepwater Horizon Incident in 2010, and thereafter worked as an Emergency Response Consultant with The Response Group for 1^1/2 years. While with Amoco and BP, he served, among other roles, as an Asset Manager and an Operations Manager for Deep Water assets, Operations Director for Gulf of Mexico and the Organizational Capability Manager. Pursuant to a settlement between the SEC and Mr. Seilhan, in April 2014, (i) the SEC filed a complaint in the U.S. District Court for the Eastern District of Louisiana alleging that Mr. Seilhan sold securities while in possession of material nonpublic information and in breach of duties owed to BP and its shareholders, in violation of federal securities laws and (ii) without admitting or denying any allegations, Mr. Seilhan consented to the entry of a final judgment therein permanently enjoining him from future violations of such federal securities laws, and agreeing to a disgorgement and payment of interest and a civil penalty.

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Richard L. Toothman, Jr. was named Senior Vice President-Appalachia in February 2013 and Vice President-Appalachia in May 2010. Prior to joining Stone in May 2010, he was employed by CNX Gas Company in Bluefield, Virginia since August 2005 where he held two executive positions, VP Engineering and Technical Services and VP International Business. He also worked for Consol Energy and Conoco in prior years.

Florence M. Ziegler was named Senior Vice President-Human Resources, Communications and Administration in February 2014 and Vice President-Human Resources, Communications and Administration in September 2005. She has been employed by Stone since its inception in 1993 and served as the Director of Human Resources from 1997 to 2004.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act and related regulations require our Section 16 officers and directors and persons who beneficially own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the SEC and the NYSE. Section 16 officers, directors and greater than 10% beneficial owners are also required by SEC regulation to furnish us with copies of all Section 16(a) forms they file.

Based solely on our review of copies of such forms we received, we believe that, during the fiscal year ended December 31, 2016, our Section 16 officers, directors and greater than 10% beneficial owners timely complied with all applicable filing requirements of Section 16(a).

Corporate Governance

The Board of Directors of Stone (the "Board") has adopted several governance documents to guide the operation and direction of the Board and its committees, which include Corporate Governance Guidelines, a Code of Business Conduct and Ethics (which applies to all directors and employees, including our Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer) and charters for the Audit, Compensation, Nominating & Governance and Reserves Committees. Each of these documents is available on our website (www.stoneenergy.com), and stockholders may obtain a printed copy, free of charge, by sending a written request to Stone Energy Corporation, Attention: Secretary, 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508, facsimile number (337) 521-9845. We will also promptly post on our website any amendments to these documents and any waivers from the Code of Business Conduct and Ethics for our directors and principal executive, financial and accounting officers.

Audit Committee Report

The Audit Committee of the Board assists the Board in monitoring (1) the integrity of the financial statements of Stone; (2) the independent registered public accounting firm’s qualifications, independence and performance; (3) the effectiveness and performance of Stone’s internal audit function and independent public accountants; and (4) the compliance by Stone with legal and regulatory requirements.

The Board has determined that each of the members of the Audit Committee satisfies the standards of independence established under the SEC's rules and regulations and listing standards of the NYSE. The Board has further determined that each of the members of the Audit Committee is financially literate and that each of Ms. Priestly and Messrs. Kinnear, Murley and Powell is an “audit committee financial expert” as defined by the rules and regulations of the SEC.

In connection with our consolidated financial statements for the year ended December 31, 2016, the Audit Committee has:


•	reviewed and discussed the audited consolidated financial statements contained in Stone’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 with management;


•	approved the appointment of Ernst & Young LLP to serve as Stone’s independent registered public accounting firm for the fiscal year ending December 31, 2017;


•	discussed with Stone’s independent registered public accounting firm, Ernst & Young LLP, the matters required to be discussed by Auditing Standard No. 16; and


•	received the written disclosures and the letter from Ernst & Young LLP as required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communications with the Audit Committee concerning independence, and discussed with Ernst & Young LLP its independence from Stone and its management.

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Based on the review and discussions with Stone’s management and independent registered public accounting firm, as set forth above, the Audit Committee recommended to Stone’s Board that the audited consolidated financial statements be included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, for filing with the SEC.



			Audit Committee,

			Kay G. Priestly - Chairman
			Peter D. Kinnear
			David T. Lawrence
			Robert S. Murley
			Donald E. Powell

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

Summary of Our Compensation Program

The Compensation Committee of our Board (the "Compensation Committee") oversees our executive compensation program. The cornerstone of our program is "pay-for-performance," aligning the interests of our Named Executive Officers ("NEOs") with those of our stockholders. We pay our employees for delivering value to our stockholders, while reducing overall compensation levels if we do not achieve our performance goals. The Compensation Committee is responsible for ensuring that our program supports the Company’s strategies and objectives in a manner consistent with these principles.

This Compensation Discussion and Analysis ("CD&A") provides important information on our executive compensation program and explains the compensation decisions made by the Compensation Committee for our NEOs for fiscal 2016. For 2016, our NEOs were:



Name		Principal Position
David H. Welch		Chairman of the Board, President and Chief Executive Officer
Kenneth H. Beer		Executive Vice President and Chief Financial Officer
Lisa S. Jaubert		Senior Vice President, General Counsel and Secretary
Keith A. Seilhan		Senior Vice President-Gulf of Mexico
Richard L. Toothman, Jr.		Senior Vice President-Appalachia

2016 Overview and 2017 Update

As an oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties, we have experienced significant declines in oil, natural gas and NGL prices since the beginning of the second half of 2014 resulting in reduced revenue and cash flows, causing us to reduce our planned capital expenditures and adversely affecting the estimated value and quantities of our proved oil, natural gas and NGL reserves. Effective June 13, 2016, we implemented a 1-for-10 reverse stock split, pursuant to which every 10 shares of our issued and outstanding common stock were converted into one share of common stock. In October 2016, we entered into the Original RSA, and in December 2016, we entered into the A&R RSA, with the Noteholders and Banks to support a restructuring on the terms of a prepackaged plan of reorganization. We also entered into a purchase and sale agreement to sell our approximately 86,000 net acres in the Appalachia regions of Pennsylvania and West Virginia in connection with the Original RSA. As contemplated by the A&R RSA, we filed for voluntary relief under Chapter 11 of the Bankruptcy Code on December 14, 2016, and following a successful auction process for the foregoing Appalachia assets, our prepackaged joint plan of reorganization was confirmed on February 15, 2017. We are targeting February 28, 2017, as the date by which we will have completed all necessary requirements to effectuate the plan of reorganization, and emerge a stronger, more competitive company, although we can make no assurances as to when, or ultimately if, the plan of reorganization will become effective.

Despite the very difficult market conditions, we had several significant achievements in 2016 and early 2017, and we believe our executive compensation program plays a significant role in driving our operational and financial results. For a complete discussion of 2016 results and our 2017 outlook, please see Item 7. Management’s Discussion and Analysis of Financial

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Condition and Results of Operations, where we have detailed our full financial and operating results for fiscal 2016 and our outlook for fiscal 2017.

2016 Compensation Decisions and Actions

As in prior years, the Compensation Committee engaged Pearl Meyer, an independent compensation consultant (referred to herein as "Pearl Meyer" or the "Compensation Consultant"), to review the overall competitiveness of the Company’s executive compensation program for 2016, with continued focus on ensuring the alignment of management compensation with performance. Although the Compensation Committee determined not to change our overall compensation philosophy for 2016, the Compensation Committee determined to break from its historic approach to focus our NEOs and other employees on achieving short-term objectives that the Compensation Committee and the Board believed to be necessary in order to preserve longer-term value. In that regard, the Compensation Committee decided to make the following changes and decisions with respect to our compensation program for 2016:

•

Salaries Remained Frozen: Due to the continued commodity price uncertainty, none of the NEOs received a base salary increase for 2016, which remained frozen at the same level as their respective 2015 base salaries, except for Mr. Seilhan whose base salary was increased effective July 1, 2016, in recognition of the additional duties and responsibilities he assumed at that time. As our CEO and CFO salaries were also not increased in 2015 either, their salaries have remained the same since 2014.

•

Traditional Long-Term and Short-Term Incentive Programs Suspended: Although our historical practice has been to make long-term equity incentive awards (usually in the form of restricted stock) in the first quarter of year as the final piece of Total Direct Compensation ("TDC") for our NEOs for performance for the prior year, we decided not to award any long-term equity incentive awards in 2016 for 2015 performance and to suspend the historical annual cash incentive compensation award and long-term equity incentive compensation programs for 2016, in recognition of the challenges to the Company from continued low commodity prices and market volatility, limitations on share availability in our Stock Incentive Plan and other forward looking-considerations. In place of these suspended programs, we implemented the 2016 Performance Incentive Compensation Plan (the "2016 Incentive Plan") described below.

•

Target TDC Opportunities Remain Significantly Reduced: For 2015, actual TDC for our NEOs was comprised only of base salary and annual cash incentive compensation paid out at 20% of target. With no long-term equity incentive award grants for 2015 performance (which would have been awarded in early 2016), this result placed us below the 25th percentile of our Peer Group for TDC. This posture was significantly below our standing at the 42.5th percentile versus our Peer Group in terms of relative Total Stockholder Return ("TSR") over the prior one-year and three-year periods. In a normal year we would have targeted 2015 TDC at a level comparable with this level of TSR performance. TDC for the NEOs and other executives for 2016 was set at a level such that target performance under the 2016 Incentive Plan would produce 25th percentile TDC for the year as compared to our peers.

•

Single Incentive Compensation Program for 2016 Performance: In place of our traditional programs, we implemented the 2016 Incentive Plan, a short-term performance cash incentive plan designed to incentivize our NEOs and other employees to meet critical short-term liquidity and capital expenditure goals in order to promote sustainable stockholder value over the long-term and preserve our longer-term prospects. As part of this program, each NEO had a single incentive opportunity that could be earned throughout the year in return for hitting challenging performance targets. Despite the absence of long-term equity incentive grants for our NEOs in 2016, our entire executive management team remained closely aligned with stockholder interests through compliance with the Company’s existing stock ownership and retention guidelines, prior-year equity incentive grants that continued to vest over the remaining applicable vesting periods, and an emphasis on near-term measures designed to focus our NEOs on preserving stockholder value.

In connection with the A&R RSA and our bankruptcy filing, on December 13, 2016, our executive officers, including the NEOs, and the Company entered into the Executive Claims Settlement Agreement (the "Settlement Agreement"), pursuant to which the parties agreed, among other things, to modify the executives’ existing change in control and severance arrangements, the Company’s Deferred Compensation Plan (the "Deferred Compensation Plan") and the employment agreements with certain NEOs on the terms and subject to the conditions of the Settlement Agreement. In addition, pursuant to the Settlement Agreement, the Company and our executive officers agreed that the officers would waive their claims related to the 2016 Incentive Plan for the fourth quarter of 2016 and any annual true-up in exchange for participation in the Company’s Key Executive Incentive Plan ("KEIP"), which will become effective upon our emergence from bankruptcy. Please see "-2017 Compensation Arrangements" below for additional information regarding the Settlement Agreement and the compensation of our NEOs for 2017.

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Say-on-Pay Advisory Votes

Our Board and the Compensation Committee take stockholder support of our executive compensation program very seriously, and we aspire to achieve the full support of our stockholders. Over the past several years we have engaged in robust stockholder outreach efforts regarding the design of our executive compensation program. The advisory vote on executive compensation at our 2016 annual meeting reflected strong support, with over 93% of the votes cast in favor. Because we do not expect to hold an annual meeting during fiscal year 2017, our next advisory votes on executive compensation (which have historically occurred on an annual basis) and on the frequency of future say-on-pay votes likely will not occur during 2017; however we intend to hold such advisory votes when next required by SEC rules.

The Board and the Compensation Committee reviewed the results of the advisory vote on executive compensation from the 2016 annual meeting and determined not to make any material changes to our 2016 program based on the results of that vote. However, the Compensation Committee and the Board, with the assistance of Pearl Meyer, did undertake a review of the Company’s compensation program and the compensation programs of industry peers and made changes for 2016 as discussed herein.

Our Compensation Philosophy

The Compensation Committee and our Board believe that the most effective executive compensation program is one based on two factors, market competitiveness and pay-for-performance, both of which are aligned with the interests of stockholders.



MARKET COMPETITIVENESS	We seek to provide competitive total compensation opportunities that attract, retain and motivate the executive talent needed to operate and grow a successful business and respond to competitive market forces.
PAY-FOR-PERFORMANCE	We promote alignment of interests between stockholders and our NEOs by linking a significant portion of pay to incentives that reward:
	●	Achievement of positive annual performance, both on an absolute and relative basis; and
	●	Creation of long-term stockholder value.

In support of these two guiding principles, we have historically taken the following approach to establishing pay levels:


•	Base Salary Below Market Median: We target base salaries below the market median and generally at the 25th percentile of the market.

•

Emphasis on Incentive Compensation: We have historically provided the opportunity (through annual incentives and long-term incentives) for our NEOs to realize pay that may range anywhere between the 10th percentile and the 90th percentile of the TDC reported in market data, depending on performance. For 2016, we provided the opportunity for our NEOs to realize pay targeted at the 25^th percentile of the market TDC of our peers to account for current circumstances.

•

TDC Commensurate with our Performance: The TDC of our NEOs is generally intended to be reflective of our relative TSR performance. Unless otherwise noted, when our TSR performance is discussed in this CD&A it refers to the average of our one-year and three-year TSR performance (weighted equally) and is considered relative (on a percentile basis) to the same TSR calculation for our Peer Group companies.

Historically we have defined TDC as the sum of the following components:


•	Base Salary (fixed pay)


•	Incentive Compensation (variable pay), which includes:

For years prior to 2016, both (a) annual cash incentive compensation rewarding performance over the short-term (current year) through a combination of formulaic and qualitative assessments covering both absolute and relative company performance metrics, and (b) long-term incentive compensation, generally in the form of restricted stock awards, rewarding the creation of long-term (multi-year) growth in value and ensuring alignment between our NEOs and our stockholders; and


2.	For 2016, compensation awarded under the 2016 Incentive Plan to incentivize achievement of critical short-term liquidity and capital expenditure goals to promote sustainable stockholder value over the long-term.

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Elements of Our 2016 Executive Compensation Program

The purposes and characteristics of each element of our executive compensation program for 2016, including base salary and awards under the 2016 Incentive Plan (which are the two components that comprise TDC for 2016), are summarized below:



Form	Purpose/Terms
Base Salary	●	Fixed compensation that is reviewed annually and adjusted if and when appropriate
	●	Generally targeted at the 25th percentile of market data
	●	Reflects each NEO’s level of responsibility, leadership, tenure, qualifications and contribution to the success and profitability of the company and the competitive marketplace for executive talent specific to our industry
2016 Performance Incentive Compensation Plan Awards *Pursuant to the Settlement Agreement entered into in December 2016, executives waived fourth quarter 2016 payments under the 2016 Incentive Plan in exchange for participation in the KEIP. See “-2017 Compensation Arrangements.”	●	Variable incentive awards tied to performance metrics that are intended to focus on near-term achievements, which are settled in cash (with a 10% portion of the CEO’s award settled in shares)
	●	Motivates our NEOs to achieve our short-term financial and operating objectives that are critical to preservation of our longer-term prospects, which reinforces the link between the interests of our NEOs and our stockholders
	●	Participation by all company employees encourages consistent behavior across the company
	●	Awards are set at a level such that target performance will produce 25th percentile TDC for 2016
	●	Capped at 150% of the targeted award
	●	Performance goals are measured and payouts are designed to be made both on a quarterly and annual basis to drive performance to address current liquidity and business needs
401(k) Plan	●	Provides for pre-tax employee deferrals up to IRS approved limit and discretionary match
	●	In 2016, the Board approved a 50% match
Deferred Compensation Plan	●	Provides for pre-tax employee deferrals for eligible employees, including our NEOs, to accumulate additional retirement savings
Health and Welfare Benefits	●	NEOs are eligible to participate in the same health and welfare benefits available to all salaried employees
Perquisites	●	Limited perquisites, including club memberships for certain NEOs responsible for business development and employee recruitment
Severance and Change in Control Benefits	●	Provide for involuntary severance and change in control protection intended to retain NEOs and to minimize distraction in the event of a corporate transaction
*Pursuant to the Settlement Agreement entered into in December 2016, the executives’ existing change in control and severance arrangements and the employment agreements were modified and we adopted a new Executive Severance Plan. See “Potential Payments upon Termination or Change of Control.”

Rationale for Fiscal 2016 Compensation

Historically, TDC for our NEOs has been targeted at or near the percentile of the average of our one-year and three-year TSR performance relative to our Peer Group. For example, if the average of our one-year and three-year TSR (weighted equally) through the end of a given year is at the 40th percentile relative to our Peer Group, the targeted TDC of our executive officers, including the NEOs, for that year will generally be set at or near the 40th percentile of the market data.

The "market data" used for these purposes consists of the combination of compensation data provided by the Effective Compensation, Inc. ("ECI") Annual Oil & Gas E&P Industry Compensation Survey for the given year and Peer Group proxy statement data. ECI Annual Oil & Gas E&P Industry Compensation Survey and Peer Group proxy statement data are combined (with the Peer Group data weighted 60% and the ECI Annual Oil & Gas E&P Industry Compensation Survey data weighted 40%)

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to create the "market data" or "marketplace" referred to throughout our CD&A. Please read "-Alignment of Pay and Performance-Peer Group for Assessing Pay and Performance" below for more information. Where TDC is used in reference to market data, the timing of payment of incentive compensation by our peers may not always align perfectly with our timing; however, we believe TDC provides an accurate representation of market data for purposes of aligning the compensation of our NEOs with our performance relative to the performance of other companies within our industry with which we compete for talent.

In establishing the applicable target TDC percentile for the NEOs for a given year, in addition to relative TSR performance, the Compensation Committee may also consider in its discretion absolute company performance on various financial and operating metrics and other strategic milestones, including without limitation growing reserves, positive results in hedging activity, changes in absolute stock performance, risk mitigation, managing lease operating expenses, acreage acquisitions and divestitures, changes in net asset value and new field discoveries. In addition, the Compensation Committee retains the discretion to consider competitive pressures, retention concerns, emerging industry trends, and individual executive performance in order to ensure our compensation program remains flexible and reactive to a volatile marketplace.

Once the target TDC percentile is established for our NEOs for a given year, TDC has historically (for years prior to 2016) been allocated among three TDC components (base salary, annual cash incentive compensation and long-term equity incentive awards) as follows:



Officer	Base Salary	Annual Incentive Award	Long-Term Incentive Award
CEO	25th percentile of market data	0-2.4x base salary	TDC minus Base Salary minus Annual Incentive Award paid
Other NEOs	25th percentile of market data	0-2.0x base salary	TDC minus Base Salary minus Annual Incentive Award paid

The Compensation Committee assesses each NEO’s performance and contribution in terms of TDC relative to the marketplace and then has historically set the grant date value of the actual long-term equity incentive awards. In years past, the annual incentive award is actually paid, and the long-term equity incentive award has then historically been granted, early in the year immediately following the relevant performance year.

For 2015, in response to the challenges to the Company from continued low commodity prices and market volatility, our enhanced focus on near-term performance objectives with the goal of creating sustainable, long-term value, and the dramatic reduction in available equity in our Stock Incentive Plan, the Compensation Committee used its discretion not to make long-term incentive grants of time-vested restricted shares in 2016 for 2015 performance, which normally would have been included in our NEOs’ TDC for 2015. As a result, our NEOs’ TDC for 2015, as we historically have measured it, was below the 25th percentile of our Peer Group, which was well below our level of relative TSR performance (42.5th percentile) for 2015.

For 2016, the Compensation Committee suspended the historical annual cash incentive compensation award and long-term equity incentive compensation programs and instead implemented the 2016 Incentive Plan. In connection with that decision, the Compensation Committee used its discretion and determined, based on the Company’s then-current circumstances, that TDC for the NEOs and other executives for 2016 should be set at a level such that target performance under the 2016 Incentive Plan would produce 25th percentile TDC for the year as compared to our peers.

Alignment of Pay and Performance

Peer Group for Assessing Pay and Performance

In 2016, the Compensation Committee used the following Peer Group, along with the ECI Annual Oil & Gas E&P Industry Compensation Survey for 2016 (the "ECI 2016 Survey"), in determining the percentile targets for pay elements of TDC for our NEOs. Where references are made throughout the CD&A to our peers or our Peer Group, including to our TSR Performance relative to our peers or our Peer Group, it is the collection of peer companies below that constitutes those peers.

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	Compensation Peer Group
●	Cabot Oil & Gas Corporation	●	Energy XXI (Bermuda) Limited	●	SandRidge Energy, Inc.
●	Callon Petroleum Company	●	Exco Resources Inc.	●	SM Energy Company
●	Carrizo Oil & Gas, Inc.	●	Newfield Exploration Company	●	Swift Energy Company
●	Cimarex Energy Company	●	PDC Energy	●	Ultra Petroleum Corporation
●	Comstock Resources, Inc.	●	PetroQuest Energy, Inc.	●	W&T Offshore, Inc.
●	Contango Oil & Gas Company	●	Range Resources Corporation	●	Whiting Petroleum Corporation
●	Denbury Resources Inc.

Our Peer Group is developed taking into consideration peer company metrics such as asset size, revenues and enterprise value, similar strategies, comparability of asset portfolio and basins and availability of compensation data. Our Peer Group consists of companies:


•	With whom we compete in our industry for executive talent and stockholder investment;


•	Similar to us in terms of size, scope and nature of business operations, including geographic footprint and operational focus, with some larger and some smaller in size and scope; and


•	That (for the most part) participate in the ECI 2016 Survey used to determine the target TDC of the competitive marketplace.

The Peer Group is periodically reviewed and updated by Pearl Meyer to ensure that the group is reasonable and remains appropriate for us and our compensation program. Decisions on any changes to the Peer Group are recommended by the Compensation Consultant and our CEO to the Compensation Committee before receiving final approval by the Board. In making compensation decisions at the beginning of 2016 and in light of the Company’s circumstances at the time, the Compensation Committee considered peer data with respect to the same Peer Group companies that comprised the 2015 Peer Group (which companies are listed above), for purposes of establishing TDC.

The Compensation Committee, our Board and our management understand the inherent limitations in using any peer group or data set. For example, there are fluctuations in survey participation from year to year, and we compete for executive talent with peers that are, in some cases, significantly larger than us. However, we believe we have established a sound review process that seeks to mitigate these limitations, including taking into consideration differences and similarities between us and the companies in our Peer Group when referencing benchmarks for NEO compensation. In connection with the Compensation Committee’s determinations of 2016 compensation for our NEOs, the Compensation Consultant provided the Compensation Committee with an analysis of prevailing compensation levels in the marketplace, including our industry peers, which analysis was adjusted for relative company size and revenue.

ECI 2016 Survey Data for Assessing Pay and Performance

The ECI 2016 Survey utilized by the Compensation Committee provided data for over 357 jobs found in exploration and production firms in the United States. While participation varies from year to year, there were 92 participants in ECI’s 2016 Survey, and 11 of the 20 companies in our 2016 Peer Group, including us, participated in the ECI 2016 Survey.


•	The data collected from the ECI 2016 Survey is intended to reflect pay rates for positions in the market that have responsibilities similar to those of our NEOs. To the extent possible for each position, we attempt to collect data from the Independent Public Company category in the ECI Survey for the Peer Group.

•

We believe the ECI 2016 Survey provides us with a meaningful market reference point for those companies with whom we most closely compete for executive talent and, consequently, with sufficient information on competitive employment market dynamics, to fashion a competitive compensation program designed to attract and retain those highly capable employees necessary for us to be competitive in our industry.

Role of Compensation Committee and Management

The Compensation Committee is responsible for determining, with Board review, the approval and adoption of all compensation decisions for each of the NEOs. The Compensation Committee’s approach is not formulaic but consists of both subjective and objective considerations. The Compensation Committee considers our overall performance, including absolute operational and financial performance, and the overall performance of the executive officer team, including the role and relative contribution of each of its members. Each NEO’s impact during the year, and his or her overall value to the Company, is assessed through evaluating long-term and current performance in the officer’s primary area of responsibility, strategic initiatives, leadership,

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market competition for the officer’s position and the officer’s role in succession planning and development and other intangible qualities that contribute to corporate and individual success.

In making compensation decisions for the NEOs, the Compensation Committee relies, in part, on input from the CEO and our Senior Vice President-Human Resources, Communications and Administration ("SVPHR"), who provide information and make recommendations, as appropriate, concerning executive compensation. Input from management typically includes the following:

•

The CEO proposes base salary amounts for executives other than himself based on his evaluation of individual performance and expected future contributions, a review of market data to ensure competitive compensation against the external market, including the Peer Group, and current industry conditions, and comparison of the base salaries of the executive officers who report directly to the CEO to ensure that each officer’s salary level accurately reflects that officer’s relative skills, responsibilities, experiences and contributions.


•	The CEO also makes recommendations to the Compensation Committee relating to our performance measures, targets and similar items that affect incentive compensation.


•	The CEO typically attends a portion of each Compensation Committee meeting to review and discuss executive compensation matters but does not participate in deliberations relative to his own pay.


•	The SVPHR submits compensation data to, and collects data from, industry-specific compensation survey sources described above, coordinates the flow of information between the Compensation Consultant and the Compensation Committee as directed by the Compensation Committee, and provides to the Compensation Committee recommendations for appropriate position matches for each NEO.

While the Compensation Committee considers it important to receive information and recommendations from the CEO, the SVPHR and the Compensation Consultant, it does not delegate these compensation decisions to the CEO, the SVPHR, the Compensation Consultant or any other party.

Role of the Compensation Consultant

The Compensation Committee may solicit input from an independent compensation consultant from time to time in making executive compensation decisions. In general, the role of our outside compensation consultant is to assist the Compensation Committee in analyzing executive pay packages and understanding our financial measures relating to compensation, but the Compensation Committee is under no obligation to follow the advice or recommendations of any compensation consultant.

The Compensation Committee has the sole authority to hire independent compensation consultants and, for 2016, the Compensation Committee engaged Pearl Meyer directly as its independent compensation consultant. The Compensation Committee solicited input from Pearl Meyer regarding compensation practices within our Peer Group, within the oil and gas marketplace and within the broader general industry marketplace for the United States. Pearl Meyer also assists the Compensation Committee by preparing reports regarding TDC within the marketplace, and TSR both with respect to the performance of our stock and the stock of our Peer Group, as well as reviews and recommendations regarding pay practices and programs for executives and directors.

The Compensation Committee regularly reviews the services provided by its outside consultant and believes that Pearl Meyer is independent under applicable SEC rules in providing executive compensation consulting services. In making this determination, the Committee noted that during fiscal 2016:


•	Pearl Meyer did not provide any services to the Company or our management other than services requested by or with the approval of the Compensation Committee, which were limited to executive and director compensation consulting;


•	Pearl Meyer maintains a conflicts policy, which was provided to the Compensation Committee, with specific policies and procedures designed to ensure independence;


•	We have been advised by Pearl Meyer that the fees we paid to Pearl Meyer in 2016 ($47,356.39) were less than 1% of Pearl Meyer’s total revenue;


•	None of the Pearl Meyer consultants working on our matters had any business or personal relationship with any Compensation Committee members;

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•	None of the Pearl Meyer consultants working on our matters had any business or personal relationship with any of our executive officers; and


•	None of the Pearl Meyer consultants working on our matters owns our stock.

The Compensation Committee continues to monitor the independence of the Compensation Consultant on a periodic basis.

Components of 2016 Executive Compensation

Base Salary

While the Compensation Committee believes it is crucial to provide salaries within a competitive market range in order to attract and retain personnel who are highly talented, the Compensation Committee has historically adhered to a philosophy of generally providing more conservative base salaries, as compared to the competitive market, in combination with more aggressive incentive compensation opportunities in order to strongly emphasize pay-for-performance. This approach has generally resulted in salaries for our NEOs targeted at the 25th percentile of our market data.

Base salaries are primarily based on job responsibilities and individual contributions. We identify analogous base salary levels of executives in the market data based on each officer’s level of responsibility, leadership role, tenure and contribution to our success and profitability. The Compensation Committee reviews base salaries on an annual basis and adjusts them if they deviate substantially from the market data or other changes or circumstances warrant a revision. These base salary levels are also reviewed by the Compensation Committee in determining severance and change in control benefits.

Considering the recommendations of the CEO (as to executives other than himself) and as approved by the Compensation Committee, on July 1, 2016, the Board approved and adopted the base salaries of our NEOs for the remainder of the 2016 year as set forth in the table below. Of the NEOs, only Mr. Seilhan received a base salary increase for 2016, which was effective July 1, 2016, and 2016 base salaries for the other NEOs remained frozen at the same level as their respective 2015 base salaries due to the continuous commodity price uncertainty. Messrs. Welch and Beer's salaries have not been increased since 2014. Mr. Seilhan’s base salary was increased in 2016 to reflect the additional duties and responsibilities he assumed in connection with certain workforce reductions and the other increased efforts by Mr. Seilhan to support the Company in the current circumstances.



Officer	2015 Base Salary		2016 Base Salary
David H. Welch	$	650,000	No change
Kenneth H. Beer	380,000		No change
Lisa S. Jaubert	300,000		No change
Keith A. Seilhan	290,000		320,000
Richard L. Toothman, Jr.	300,000		No change

Performance Incentive Compensation

The Compensation Committee and the Board determined that it was in the best long-term interest of the Company to suspend the Company’s historic annual cash incentive compensation program for 2016. As a result, no annual cash incentive compensation awards were made under our 2005 Annual Incentive Compensation Plan ("Annual Incentive Plan") to any NEO for 2016 performance. In place of our traditional programs, our NEOs received awards under the 2016 Incentive Plan for 2016, which are described in greater detail below.

The Board, upon recommendation of the Compensation Committee, adopted the 2016 Incentive Plan in March 2016. The 2016 Incentive Plan is intended to motivate the Company’s employees, including the NEOs, to make extraordinary efforts to achieve short-term target goals crucial to the Company and, for 2016, comprised the entire incentive-based compensation opportunity for participants. All of our employees, not just the NEOs and other executives, were eligible to participate in the 2016 Incentive Plan, thereby encouraging consistent behavior across the Company.

Under the 2016 Incentive Plan, the extent to which award opportunities may be earned is based on performance achieved for each fiscal quarter of 2016 (each, a "Quarterly Period"), with the opportunity to earn additional amounts at the end of fiscal year 2016 (the "Annual Period") based on performance over the full year (the "Annual True-Up").

For each NEO, the Compensation Committee determined a threshold, target and maximum award opportunity expressed as a percentage of base salary, for each Quarterly Period and the Annual Period. In light of the near-term focus of the 2016 Incentive Plan, we capped the potential payout of the NEOs’ award opportunity under that plan at 150% of the targeted award as compared

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to our historical approach of having a maximum 200% of target payout under the Annual Incentive Plan. The award opportunities for each NEO under the 2016 Incentive Plan are set forth in the table below:



		Quarterly Period Award Opportunity						Annual Period Award Opportunity
Officer	Target Percentage of Base Salary	Threshold (50%)		Target (100%)		Maximum (150%)		Threshold (50%)		Target (100%)		Maximum (150%)
David H. Welch	450%	$	365,625	$	731,250	$	1,096,875	$	1,462,500	$	2,925,000	$	4,387,500
Kenneth H. Beer	300%	142,500		285,000		427,500		570,000		1,140,000		1,710,000
Lisa S. Jaubert	275%	103,125		206,250		309,375		412,500		825,000		1,237,500
Keith A. Seilhan	197%	78,750		157,500		236,250		315,000		630,000		945,000
Richard L. Toothman, Jr.	190%	71,250		142,500		213,750		285,000		570,000		855,000

The Compensation Committee also approved the performance measures set forth in the table below for the 2016 Incentive Plan, along with their relative weightings (expressed in terms of allocated points for threshold, target and maximum performance). In implementing the 2016 Incentive Plan, we eliminated any discretionary component, which was a feature of the annual cash incentive compensation program for 2015, as well as the one-year relative TSR component.



Performance Measures	Potential Points
Performance Measures	Threshold	Target	Maximum
EBITDA ($ millions) EBITDA (earnings before interest, taxes, depletion and amortization) is calculated as pre-tax income plus (1) interest expense, (2) depreciation, depletion, amortization and accretion, (3) rig expenses (shifted to capital spending), and (4) non-recurring items.	25	50	75
Capital Expenditures ($ millions) The Capital Expenditures factor is calculated as capital expenditures plus rig expenses (shifted from EBITDA).	20	40	60
Health, Safety and Environmental (HSE) Performance The HSE factor includes personal safety (weighted 50%), environmental safety (weighted 30%) and compliance safety (weighted 20%). Personal safety is measured based on total recordable incident rate (TRIR) performance for employees and certain contractors, environmental safety is measured by reported spills of hydrocarbons, and compliance safety is measured by fines or penalties paid to state or federal regulatory agencies. HSE is included as a performance measure because maintaining a healthy workforce is critical to ensuring execution of our business plan. There is also a strong correlation between positive long-term business performance and solid safety performance. We also believe it is in the interest of stockholders to prevent accidents, protect the environment and comply with applicable laws and regulations.	5	10	15
TOTAL POINTS	50	100	150

The Compensation Committee also established minimum, target and maximum goals for each performance measure with respect to each Quarterly Period and the Annual Period. These performance goals were subject to adjustment by the Compensation Committee in accordance with the terms of the Company’s Stock Incentive Plan. The performance measures and goals implemented in connection with the 2016 Incentive Plan differ in certain respects from the performances measures and associated goals utilized under the Company’s annual cash incentive compensation program for 2015. However, we believe these goals maintained the same rigor and level of difficulty as the prior year goals in light of changing market conditions. Further, these goals and the quarterly and annual payout design were intended to drive immediate short-term financial and operating performance to address our current liquidity and business needs, which the Compensation Committee and the Board believed to be necessary in order to preserve longer-term value. The performance goals for the Annual Period are reflected in the following table with goals and performance results for specific Quarterly Periods set forth below.

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Performance Measure	Annual Period Performance Goals
Performance Measure	Threshold		Target		Maximum
EBITDA ($ millions)	$	117.30	$	138.00	$	158.70
Capital Expenditures ($ millions)	$	215.00	$	195.00	$	175.00
HSE Score	0.37		0.27		0.17

Following the end of each applicable period, the Compensation Committee determined the level of achievement of the performance goals and the extent to which the award opportunities had been earned, and earned amounts are payable as soon as practicable thereafter but in no event later than March 15, 2017. The 2016 Incentive Plan provides that, following the end of the 2016 fiscal year, the Compensation Committee will determine the level of achievement of the performance goals for the Annual Period and the extent to which any Annual True-Up payment was earned. For these purposes, an Annual True-Up payment is calculated as the difference, if any, between the award opportunity the Compensation Committee determines is earned for the Annual Period and the sum of the award opportunities earned and paid for all Quarterly Periods.

All earned amounts are paid in a cash lump sum, subject to applicable withholding and any compensation recovery or "clawback" policy of the Company in effect at the time of payment. Subject to shares of stock being available for issuance under the Stock Incentive Plan, 10% of the CEO’s earned award opportunities are payable in the form of fully vested shares of the Company’s common stock, as a means of continuing to link his compensation directly to our stock price and to stockholder interests. The number of shares paid equals the number determined by dividing (i) the dollar amount of 10% of the earned amount, by (ii) the average closing price of the Company’s common stock for the Quarterly Period (or, in the case of any Annual True-Up, the average closing price for the month of December 2016), subject to applicable withholding.

As described in greater detail below under "–2017 Compensation Arrangements," pursuant to the Settlement Agreement, the Company and the NEOs agreed in December 2016 that the NEOs would waive their claims related to the 2016 Incentive Plan for the fourth Quarterly Period (including the Annual True-Up) in exchange for participation in the Company’s KEIP, which will become effective upon our emergence from bankruptcy. As a result, none of the NEOs was entitled to any payments with respect the fourth Quarterly Period or to any Annual True-Up payment pursuant to the 2016 Incentive Plan.

The tables below reflect, for the first three Quarterly Periods of fiscal year 2016: (i) the applicable performance goals established for each performance measure and (ii) the actual performance attained by the Company as of the end of the applicable period. Achieving or exceeding the "maximum" performance goal for a measure earns the maximum points ascribed to such measure, with the sum of the maximum points that may be earned for achieving the maximum performance goal on all measures equaling 150 points. The Compensation Committee believes the maximum performance goal for each measure should be difficult but highly advantageous for us to achieve. No points are earned for a performance measure if less than the minimum performance goal for such measure is achieved. Results achieved between the minimum and target performance goals and the target and maximum performance goals are linearly interpolated between points. To the extent that performance goals are met, points are earned and awarded, as determined by the Compensation Committee, towards the total award opportunity for the applicable Quarterly Period. In other words, each point reflected in the table below effectively represents one percentage point of the target award opportunity for the applicable Quarterly Period.

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Performance Measure	First Quarterly Period Performance Goals						Actual Performance		Earned Points
Performance Measure	Threshold		Target		Maximum		Actual Performance		Earned Points
EBITDA ($ millions)	$	22.19	$	26.10	$	30.02	$	42.29	75
Capital Expenditures ($ millions)	$	92.35	$	83.65	$	75.18	$	86.73	33
HSE Score	0.37		0.27		0.17		0.02		15
First Quarterly Period Points:									123

Performance Measure	Second Quarterly Period Performance Goals						Actual Performance		Earned Points
Performance Measure	Threshold		Target		Maximum		Actual Performance		Earned Points
EBITDA ($ millions)	$	29.83	$	35.10	$	40.36	$	38.69	67
Capital Expenditures ($ millions)	$	46.61	$	42.32	$	37.94	$	43.08	36
HSE Score	0.37		0.27		0.17		0.16		15
Second Quarterly Period Points:									118

Performance Measure	Third Quarterly Period Performance Goals						Actual Performance		Earned Points
Performance Measure	Threshold		Target		Maximum		Actual Performance		Earned Points
EBITDA ($ millions)	$	31.96	$	37.60	$	43.24	$	48.70	50*
Capital Expenditures ($ millions)	$	33.51	$	30.42	$	27.27	$	43.50	0
HSE Score	0.37		0.27		0.17		0.27		10
Third Quarterly Period Points:									60

* Actual performance with respect to the EBITDA measure for the third Quarterly Period would have resulted in the full 75 points being earned; however, the Compensation Committee approved only 50 points considering the entirety of the circumstances.

The aggregate amount paid to each NEO with respect to the first three Quarterly Periods under the 2016 Incentive Plan is disclosed within the Summary Compensation Table as "Non-Equity Incentive Plan Compensation" for 2016, except that the portion of such amount paid to Mr. Welch in the form of shares of our common stock is disclosed in the "Stock Awards" column for 2016.

Long-Term Incentive Compensation

The Compensation Committee and the Board determined that it was in the best long-term interest of the Company to suspend the Company’s historic long-term incentive compensation program for 2015 and 2016. As a result, no long-term incentive compensation awards were made to any NEO for 2015 performance or 2016 performance. In place of our traditional programs, our NEOs received awards under the 2016 Incentive Plan for 2016. Please see "-Components of 2016 Executive Compensation-Performance Incentive Compensation" above for additional information.

Historically, awards of long-term incentive compensation have been intended to provide a substantial forward-looking incentive to our NEOs that:


•	Emphasizes long-term value creation;


•	Aligns the long-term interests of our NEOs with those of our stockholders by directly linking rewards to stockholder return; and


•	Fosters meaningful levels of long-term stock ownership by our NEOs.

Long-term incentive awards with respect to a given year’s performance have typically been granted to our NEOs in the first quarter of the following year. In determining the value of long-term incentive compensation awards for each of our NEOs for prior years, the Compensation Committee has historically determined and approved (1) the target TDC percentile based on the average of our one- and three-year TSR performance (weighted equally, and relative (on a percentile basis) to the same TSR calculation for our Peer Group companies (as previously described under “Rationale for Fiscal 2016 Compensation”)), (2) the TDC and base salary rate for each of our NEOs and (3) the total points and dollar value awarded for each NEO’s annual incentive compensation award for the applicable year in accordance with the Compensation Committee’s determination. The grant date value for each NEO’s long-term incentive compensation award was then determined by subtracting the NEO’s base salary rate and annual incentive compensation award from the NEO’s TDC amount. In addition, in establishing the grant date value of each NEO’s long-term incentive compensation, the Compensation Committee also considered other subjective factors, including an individual’s performance against strategic milestones such as positive results in growing reserves, hedging activity, liquidity, risk mitigation,

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health, safety, environmental and regulatory targets, acreage acquisition, new field discoveries, and major field acquisitions, and the Compensation Committee could adjust the grant date value of the awards in its discretion, with the Board retaining the authority to suspend or eliminate awards under the program, which it did for the 2015 performance year and the 2016 performance year.

We have historically made awards of restricted stock to employees under our Stock Incentive Plan that vest in equal annual installments over three years from the year of grant. Although these awards historically included solely time-based vesting conditions, the determination of the size of the award initially granted was tied to our relative TSR performance over the one- and three- year periods preceding the grant, as described above. The three year vesting schedule supports our retention strategy by mitigating swings in incentive values during periods of high commodity price volatility. During 2016, the NEOs continued to hold restricted stock awards previously granted to them in 2013 (for 2012 performance), 2014 (for 2013 performance) and 2015 (for 2014 performance). Please see "Outstanding Equity Awards at Fiscal Year End" and "Options Exercised and Stock Vested" below for more information about these awards. All then outstanding stock-based awards and the share limitations of the Stock Incentive Plan were adjusted in June 2016 to reflect our 1-for-10 reverse stock split.

Stock Ownership and Retention Guidelines and Prohibition on Hedging

The Board has adopted Stock Ownership Guidelines designed to further align the interests of our executive officers and directors with those of our stockholders. Executives are required to meet the following ownership levels by the later of May 23, 2017 or within five years of being promoted or appointed to their position. All of the NEOs, and all other executive officers, are in compliance with the Stock Ownership Guidelines.



Individual		Multiple of Salary(1)
Chief Executive Officer		5x base salary
Executive Vice President		4x base salary
Senior Vice President		3x base salary
Vice President		2x base salary


(1)	In effect on January 1 of the applicable year.

Among other terms, the guidelines provide that (1) restricted stock will be included in determining the stock ownership of an individual, and (2) until the applicable guideline multiple of salary is attained, an individual is required to retain, and not sell or otherwise dispose of, at least 75% of his or her net shares (after tax withholding) acquired through long-term incentive awards. For each officer, the guidelines will be reduced 15% per year beginning on the 61st anniversary of the birth date of the officer, such that the officer need comply with only 85% of the guidelines after age 61, 70% after age 62, 55% after age 63, 40% after age 64, and 25% after age 65 and thereafter until retirement or other termination of employment. The value of our stock used in determining the number of shares needed to comply with the guidelines in a given year will be the average price of our stock during August of that same calendar year. The Board may amend or terminate the Stock Ownership Guidelines in its sole discretion.

For the description of the Stock Ownership Guidelines applicable to directors, please read "Director Compensation" below.

The Board has adopted a policy prohibiting any executive officer of the Company, including the NEOs, from hedging company stock.

Clawback Policy

The Board has adopted a clawback policy under which the Board, or a committee of the Board, has the right to cause the reimbursement by an executive officer of the Company of certain incentive compensation if the compensation was predicated upon the achievement of certain financial results that were subsequently the subject of a required restatement of the Company’s financial statements and the executive officer engaged in fraudulent or intentional illegal conduct that caused the need for the restatement.

Other Program Components

The NEOs also participate in a variety of retirement, health and welfare, and paid time-off benefits that are available to all our salaried employees generally on a non-discriminatory basis. These benefits are designed to enable us to attract and retain our workforce in a competitive marketplace and to ensure that we have a productive and focused workforce. These benefit plans, and the limited perquisites we provide to our executive officers, are described in greater detail below.

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Perquisites and Other Benefits

Perquisites and other personal benefits represent a small part of our overall compensation package. These benefits help us attract and retain senior level executives and are reviewed periodically to ensure that they are competitive with industry norms. We sponsor membership in golf or social clubs for certain senior executives who have responsibility for entertainment deemed necessary or desirable to conduct business and recruit employees.

401(k) Plan

To provide employees with retirement savings in a tax efficient manner, under our 401(k) Profit Sharing Plan ("401(k) Plan"), in 2016, eligible employees were permitted to defer receipt of up to 60% of their eligible compensation, plus an additional catch-up amount for employees age 50 or over of up to $6,000 (subject to certain limits imposed by the Internal Revenue Code (the "Code")). The 401(k) Plan provides that a discretionary match of employee deferrals, before catch-up amounts, may be made by us, at our discretion and as determined by the Board, in cash or shares of our stock. During the year ended December 31, 2016, and since the inception of the 401(k) Plan, the Board has approved, and we have made, annual matching contributions of $1.00 for every $2.00 contributed by an employee up to the maximum deferral amount permitted by the Code, excluding catch-up contributions.

Deferred Compensation Plan

To provide certain executives and other highly compensated individuals with additional retirement savings opportunities, the Stone Energy Corporation Deferred Compensation Plan (the "Deferred Compensation Plan") is a non-qualified deferred compensation plan that provides eligible individuals with the option to defer up to 100% of their eligible compensation for a calendar year. The Compensation Committee may, at its discretion, match all or a portion of a participant’s deferrals based upon a percentage determined by the Board. In addition, the Board may elect to make discretionary profit sharing contributions to the plan. During the year ended December 31, 2016, and since the inception of the Deferred Compensation Plan, there were no matching or profit sharing contributions made by us. In December 2016, the Company took action to amend the terms of the Deferred Compensation Plan to eliminate the Company’s ability to make matching contributions thereunder. Please see "-2017 Compensation Arrangements" below for additional information. The amounts held under the Deferred Compensation Plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant, which are identical to the investment options available to participants in our 401(k) Plan. The "Nonqualified Deferred Compensation" section below contains additional details regarding the Deferred Compensation Plan and each NEO’s account in such plan.

Severance Plan and Change of Control Benefits

We provide severance and change of control benefits to our NEOs, which are designed to facilitate our ability to attract and retain executives as we compete for talented employees in a marketplace where such protections are commonly offered. We believe that providing consistent, competitive levels of severance protection helps minimize distraction during times of uncertainty and helps to retain our senior people. Our severance arrangements provide benefits to ease an employee’s transition in the event of an unexpected employment termination due to ongoing changes in our employment needs. The Compensation Committee is responsible for administering these arrangements. Pursuant to the terms of the Settlement Agreement, in December 2016, the Company took action to terminate or otherwise modify certain existing severance and change of control arrangements with its NEOs and adopted the Executive Severance Plan. Please see "-2017 Compensation Arrangements" below for additional information. For a detailed description of potential payments that could be made to our NEOs pursuant to these arrangements, please see the "Potential Payment Upon Termination or Change of Control" table below.

2017 Compensation Arrangements

On December 14, 2016, we filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court. In connection with our bankruptcy filing, on December 13, 2016, following approval by the Compensation Committee and the Board, we entered into the Settlement Agreement with nine of our senior executives and managers, including our NEOs. On December 14, 2016 we filed a motion seeking the Bankruptcy Court’s approval of the Settlement Agreement and of our assumption of certain amended employment agreements and the Deferred Compensation Plan, as provided in the Settlement Agreement. On January 11, 2017 the Bankruptcy Court entered an order authorizing and approving the motion. Pursuant to the terms of the Settlement Agreement, all as described in more detail below:


•	The NEOs waived their claims related to the 2016 Incentive Plan for the fourth quarter of 2016 including any Annual True-Up payment, and in exchange therefor, we adopted the KEIP (described below);

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•	NEOs who previously participated in the Company’s Executive Change of Control and Severance Plan (the "COC/Severance Plan") waived their right to receive certain change of control payments under such plan that could have been triggered upon consummation of the plan of reorganization, and in exchange therefor, we adopted the Executive Severance Plan, in which such NEOs became participants;


•	We terminated Mr. Beer’s employment agreement and entered into an amended employment agreement with Mr. Welch. As a result, Mr. Welch and Mr. Beer became participants in the Executive Severance Plan instead of being entitled to the individual severance benefits set forth in their prior agreements;

•

We amended Mr. Toothman’s employment agreement to reduce the severance benefits that would have been payable upon his termination of employment following a sale of our Appalachia properties from 2.99 times his base salary to 2 times his base salary. These benefits will offset any benefits provided to Mr. Toothman pursuant to the Executive Severance Plan and are not in addition to any Executive Severance Plan benefits to which he may become entitled; and


•	We amended the Deferred Compensation Plan to discontinue the Company’s ability to provide company matching contributions thereunder.

We determined that the revised compensation arrangements with our NEOs authorized by the Settlement Agreement are in our best interest because (1) the NEOs agreed to significant concessions that will benefit us and maximize value for all stakeholders, (2) the terms of the Settlement Agreement will result in substantially lower incentive-based compensation and severance benefits for the NEOs relative to what they otherwise could receive, thereby preserving greater liquidity for the Company, and (3) approval of the Settlement Agreement provides certainty with respect to the pool of unsecured claims and administrative expense liabilities, as the NEOs have agreed to waive significant claims that they otherwise would be entitled to assert against us in the bankruptcy.

Additionally, we have adopted the Stone Energy Corporation 2017 Long-Term Incentive Plan (the "2017 LTIP"), which is an omnibus equity compensation plan that will replace the Company’s Stock Incentive Plan and will become effective upon our emergence from bankruptcy following approval by the Bankruptcy Court. To date in 2017, no awards have been authorized under the Stock Incentive Plan (or pursuant to the 2017 LTIP which is to be effective upon the Company's emergence from bankruptcy) and the base salary rates of the NEOs have not been changed and remain at the same 2016 levels.

Stone Energy Corporation Key Executive Incentive Plan (KEIP)

Pursuant to the terms of the Settlement Agreement, the NEOs waived their claims related to the 2016 Incentive Plan for the fourth quarter of 2016, including any Annual True-Up payment, in exchange for participation in the KEIP, subject to the terms of the KEIP.

The KEIP is intended to enable us to efficiently restructure our business operations and retain the services of our essential executives. The KEIP offers carefully crafted and narrowly tailored incentives to the NEOs that will encourage and motivate them to maximize creditor recoveries and achieve our restructuring objectives. Payments under the KEIP are market-based and will result in aggregate savings to us of over $1 million compared to what the executives could have potentially received under the 2016 Incentive Plan for the fourth quarter of 2016 (plus the Annual True-Up). We believe the reduced performance bonuses under the KEIP will properly incentivize our NEOs, who possess the leadership skills and expertise critical to our ability to generate value for our stakeholders. The NEOs are in positions that are most integral to our restructuring process, including right-sizing our capital structure as well as improving operational and financial performance.

We have structured the KEIP to incentivize improvements to operational performance in the Gulf of Mexico related to production while also incentivizing management of lease operating costs related to that production and compliance with health, safety, and regulatory regulations. By linking the NEOs’ compensation opportunities to these important operational goals, the KEIP is intended to align our interests with the interests of the NEOs and our stakeholders. Specifically, the performance measures, goals and the weightings for each under the KEIP are as follows:

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Performance Measure	Weighting	Performance Goals
Performance Measure	Weighting	Threshold (50%)		Target (100%)		Maximum (200%)
Average Monthly Production Calculated as Average Net Gulf of Mexico production rate in thousand cubic feet equivalent ("MCFE") per day, disregarding any production at Amethyst, for the period January 1, 2017 through the effective date of our plan of reorganization	40%	80		100		140
Average Monthly Lease Operating Expense (LOE) Calculated as Average Net Gulf of Mexico monthly LOE, calculated by including PHA fees and excluding major maintenance expenditures, from January 1, 2017 through the end of the month in which the effective date of our plan of reorganization occurs (or the prior month)	40%	$	4.23	$	3.73	$	3.23
Safety, Environmental and Compliance (SEC) Factor Determined based upon the number of relevant Gulf of Mexico occurrences occurring in the areas of safety, environmental and compliance during a rolling 12 month period ending on the effective date of our plan of reorganization.	20%	0.37		0.27		0.17

Under the 2016 Incentive Plan, the executive officers, including the NEOs, would have been entitled to award opportunities for the fourth quarter of 2016 that could have totaled as much as $3,012,638. Pursuant to the terms of the Settlement Agreement and the executives’ waiver of these amounts, the aggregate incentive bonus for these individuals for the fourth quarter of 2016 was reduced to $0. Under the KEIP, the aggregate bonus amount that may become payable to the executives is limited to $2,008,425, which is equal to the aggregate target award opportunities the executives would have been eligible to receive for the fourth quarter of 2016 under the 2016 Incentive Plan. Payouts to the NEOs under the KEIP may not exceed the following target award opportunities: (i) Mr. Welch--$731,250, (ii) Mr. Beer--$285,000, (iii) Mrs. Jaubert--$206,250, (iv) Mr. Seilhan--$157,500, and (v) Mr. Toothman--$142,500.

Payments under the KEIP will generally be paid in cash in two installments with 50% of the award being paid as soon as practicable, but not later than 75 days following the effective date of the consummation of the plan of reorganization, and 50% paid on the 90th day following the effective date of the plan of reorganization. A participant must generally be employed by us on the applicable payment date to receive payment under the KEIP. These payment terms notwithstanding, if a participant in the KEIP is terminated without “cause” or for “good reason” (both as defined in the Executive Severance Plan), or by reason of death, such participant will be entitled to receive both the first and second payments.

Executive Severance Plan and Employment Agreements

Pursuant to the terms of the Settlement Agreement, (i) the COC/Severance Plan and Mr. Beer’s employment agreement were terminated, (ii) the employment agreements with Mr. Welch and Mr. Toothman were amended, and (iii) the Company adopted the Executive Severance Plan and each NEO became a participant therein as provided in accordance with the Settlement Agreement. As a result, the potential aggregate claims that the senior executives could assert pursuant such agreements have been significantly reduced. We have structured the reduced severance payments under the Executive Severance Plan to provide the senior executives with peace of mind during the uncertain restructuring process, but not provide them with substantial payments as a result of any change in control pursuant to the restructuring plan or any future change in control.

We have historically maintained employment agreements with Messrs. Welch, Beer and Toothman regarding their employment with us. After a thorough review process by the Compensation Committee, our advisors, and the Board, Mr. Beer’s agreement was terminated in its entirety and we amended our agreements with Mr. Welch and Mr. Toothman to provide for lessened potential benefits payable upon separation from service with us. As a result of the changes to their employment agreements, these three NEOs became participants in the Executive Severance Plan and ceased to be entitled to any severance benefits set forth in their individual agreements, except that Mr. Toothman remains eligible to receive special severance benefits if he incurs a qualifying termination of employment in connection with a disposition of our Appalachian properties. In addition, Messrs. Welch and Beer have agreed to the elimination of all rights to any potential Section 4999 gross-up payments.

Pursuant to the terms of the Executive Severance Plan, upon a participant’s "involuntary termination" (as defined in the Executive Severance Plan), such participant would be eligible to receive (i) any earned but unpaid portion of the participant’s annual salary, (ii) a lump sum cash severance payment equal to a multiple (between 1.0 and 1.5 depending on the participant) of the participant’s then-current base salary, (iii) for Mr. Welch and Mr. Beer, an additional lump sum cash payment equal to a multiple of 1.0 x their respective accrued bonus, (iv) six months of COBRA at a cost that is equal to the cost for an active employee for

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similar coverage, (v) accelerated vesting of the next tranche of any unvested, time-based equity award held by the participant, and (vi) outplacement services pursuant to our prevailing practices at the time of termination, but the cost of such services shall not exceed 5% of the participant’s annual salary. Payments and benefits under the Executive Severance Plan (except for earned, but unpaid salary) are subject to the participant’s execution and non-revocation of a release of claims agreement in our favor.

For additional information regarding the Executive Severance Plan, the amended employment agreements with Mr. Welch and Mr. Toothman, and the amounts that could become payable to our NEOs under the applicable arrangements, please see "Potential Payments Upon Termination or Change of Control" below.

Non-Qualified Stone Energy Corporation Deferred Compensation Plan

In connection with our entry into the Settlement Agreement, we adopted an amendment to the Deferred Compensation Plan that removed our ability to make matching contributions under the Deferred Compensation Plan. We believe this amendment supports our cost-cutting initiatives and overarching restructuring objectives; however, we have not historically made matching contributions under the plan. We expect to continue to maintain the Deferred Compensation Plan following our emergence from bankruptcy.

Stone Energy Corporation 2017 Long-Term Incentive Plan

We have adopted the 2017 LTIP to be effective upon our emergence from bankruptcy following approval by the Bankruptcy Court. The 2017 LTIP is substantially similar to the Stock Incentive Plan in all material respects except that, pursuant to the terms of the 2017 LTIP, the maximum number of shares of our common stock that may be issued with respect to awards under the 2017 LTIP will be equal to 10% of our authorized shares of common stock as of our emergence from bankruptcy. The 2017 LTIP will permit us to grant a variety of equity-based and other incentive compensation awards to align the interests of eligible individuals, including the NEOs, with the interests of our shareholders. However, no award determinations have been made to date.

Tax and Accounting Considerations

The Compensation Committee considers the expected tax treatment to our company and its executive officers as one of the factors in determining compensation matters. Section 162(m) of the Code generally limits the deductibility of certain compensation expenses in excess of $1.0 million to a "covered employee" in any fiscal year, although certain qualifying performance-based compensation is not subject to the limits on deductibility. For these purposes, "covered employees" consist of our CEO and the three most highly compensated executive officers other than our CEO and our Chief Financial Officer. The Compensation Committee currently considers the deductibility under Section 162(m) of the Code of compensation awarded to its executives to the extent reasonably practical and consistent with our objectives, but the Compensation Committee may nonetheless approve compensation that does not fall within these requirements and may authorize compensation that results in non-deductible amounts above the limits if it determines that such compensation is in our best interests. Payments under the 2016 Incentive Plan are intended to qualify for deduction under Section 162(m).

We have historically provided Messrs. Welch and Beer with certain tax protection in the form of a potential gross-up payment to reimburse them for excise taxes that might be incurred under Section 4999 of the Code, as well as any additional income taxes resulting from such reimbursement. However, if the total to be paid to Mr. Welch or Mr. Beer did not exceed 110% of the greatest amount (the "Reduced Amount") that could be paid to the executive such that the receipt of the total would not give rise to any excise tax, then no gross-up payment would be made and the total payments to the executive in the aggregate would be reduced to the Reduced Amount. At the time these provisions were put in place, they reflected typical market practice and they provided a valuable executive retention tool. Pursuant to the terms of the Settlement Agreement, Messrs. Welch and Beer have agreed to eliminate all rights to any potential Section 4999 gross-up payments in favor of a reduction of payments and/or benefits to each officer in whole or in part to the extent the officer’s net after-tax benefit will exceed such officer’s net after-tax benefit if such reductions are not made. Please see "-2017 Compensation Arrangements" above for additional information. Upon our emergence from bankruptcy, we anticipate that none of our NEOs or other employees will have the right to any Section 4999 gross-up payments and we do not expect to enter into any such arrangements in the future.

We are accounting for stock-based payments in accordance with the requirements of FASB ASC Topic 718.

Risks Arising from Compensation Policies and Practices

The Compensation Committee, with the assistance of the Compensation Consultant, has assessed the risks related to our compensation programs, including our executive compensation program. Based on this assessment, the Compensation Committee believes that the design and governance of our executive compensation program do not encourage our NEOs to take excessive or

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inappropriate risks and that the risks arising from the design of the programs are not reasonably likely to affect the Company in a material adverse manner.

The Compensation Committee believes that our executive compensation program is consistent with the highest standards of risk management. Rather than determining incentive compensation awards based on a single metric, the Compensation Committee considers a balanced set of performance measures that it believes collectively best indicate successful management of our assets and strategy in light of current circumstances. In addition to establishing measurable targets, the Compensation Committee applies its informed judgment to compensation decisions, taking into account factors such as quality and sustainability of earnings, successful implementation of strategic initiatives and adherence to core values. The Compensation Committee believes that the Company’s historic practice of granting long-term incentive awards of restricted stock, vesting over three years, aligns our executive officers’ interests with the interests of our stockholders and discourages short-term risk taking. The Compensation Committee, however, determined it was prudent, and reflected a better alignment with long-term interests of our stockholders, to suspend long-term incentive awards for 2015 and 2016 performance in light of the challenges facing the Company from the extended low commodity price environment and the importance of a focus on successful execution of shorter-term performance goals designed to enhance the Company’s liquidity and strengthen its balance sheet. In addition, essentially all of our employees participate in our compensation programs thereby encouraging consistent behavior across the company. We have also adopted a clawback policy that permits us to recoup certain incentive compensation based on inaccurate financial results. Together, the features of our executive compensation program are intended to ensure that our compensation opportunities do not encourage excessive risk taking and to focus our NEOs on managing our Company toward long-term sustainable value for our stockholders.

COMPENSATION COMMITTEE REPORT

The Compensation Committee does hereby state that:


•	The Compensation Committee has reviewed and discussed the foregoing "Compensation Discussion and Analysis" required by Item 402(b) of Regulation S-K with management; and


•	Based on the review and discussions with management, the Compensation Committee recommended to the Board of Directors that the "Compensation Discussion and Analysis" be included in Stone Energy Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.



		Compensation Committee,

		George R. Christmas - Chairman
		B. J. Duplantis
		Peter D. Kinnear
		Robert S. Murley
		Phyllis M. Taylor

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

No member of the Compensation Committee is now, or at any time since the beginning of 2016 has been, employed by or served as an officer of the Company or any of its subsidiaries or had any relationships requiring disclosure with the Company or any of its subsidiaries. None of our executive officers is now, or at any time has been, since the beginning of 2016, a member of the compensation committee or board of directors of another entity one of whose executive officers has been a member of our Board or Compensation Committee.

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EXECUTIVE COMPENSATION TABLES

Summary Compensation Table

The following table sets forth the compensation earned by the NEOs for services rendered in all capacities to our Company and its subsidiaries for the fiscal years ended December 31, 2016, 2015 and 2014.



Name and Principal Position	Year	Salary ($)		Stock Awards ($)(1)		Non-Equity Incentive Plan Compensation ($)(2)		All Other Compensa-tion ($)(3)		Total ($)		TDC ($)(4)
David H. Welch	2016	$	650,000	$	168,258	$	1,980,968	$	20,919	$	2,820,145	$	2,799,226
Chairman of the Board,	2015	650,000		3,910,250		130,000		21,289		4,711,539		780,000
President and Chief	2014	645,833		4,432,516		689,750		20,987		5,789,086		5,250,000
Executive Officer
Kenneth H. Beer	2016	380,000		—		857,850		9,000		1,246,850		1,237,850
Executive Vice President	2015	380,000		1,282,542		76,000		9,000		1,747,542		456,000
and Chief Financial	2014	379,167		1,659,997		337,458		8,750		2,385,372		2,000,000
Officer
Lisa S. Jaubert	2016	300,000		—		620,813		9,000		929,813		920,813
Senior Vice President,	2015	298,333		747,092		59,667		9,000		1,114,092		359,667
General Counsel and	2014	284,167		749,996		252,908		8,750		1,295,821		1,290,000
Secretary
Keith A. Seilhan	2016	305,000		—		449,783		9,000		763,783		754,783
Senior Vice President-	2015	288,333		665,992		57,667		66,000		1,077,992		347,667
Gulf of Mexico	2014	274,167		554,985		244,008		31,100		1,104,260		1,190,000

Richard L. Toothman, Jr.	2016	300,000		—		428,925		9,000		737,925		728,925
Senior Vice President-	2015	298,333		644,125		59,667		9,300		1,011,425		359,667
Appalachia	2014	287,500		639,984		255,875		8,750		1,192,109		1,190,000

(1)

Stock awards reflected in this column were made pursuant to our Stock Incentive Plan. The values shown in this column reflect the aggregate grant date fair value of restricted stock or other awards granted in the given year, computed in accordance with FASB ASC Topic 718, determined without regard to possible forfeitures. The value ultimately received by the executive officer may or may not be equal to the values reflected above. See Note 13 to our audited financial statements included herein for the year ended December 31, 2016 for a complete description of the valuation, including the assumptions used.

The value reported for Mr. Welch in 2016 represents the 10% portion of Mr. Welch’s earned award opportunity under the 2016 Incentive Plan for the first, second and third Quarterly Periods that was payable in the form of the Company’s common stock pursuant to the Stock Incentive Plan. The number of shares paid equals the number determined by dividing (i) the dollar amount of the applicable 10% portion, by (ii) the average closing price of the Company’s common stock for the Quarterly Period, subject to applicable withholding. The shares of stock were delivered to Mr. Welch: (a) with respect to the first Quarterly Period, on May 6, 2016, when the price of our common stock was $7.35 (as adjusted to reflect our 1-for-10 reverse stock split), (b) with respect to the second Quarterly Period, on August 5, 2016, when the price of our common stock was $10.23, and (c) with respect to the third Quarterly Period, on November 7, 2016, when the price of our common stock was $4.03. The cash portion of Mr. Welch’s earned award opportunity is reflected in the "Non-Equity Incentive Plan Compensation" column for 2016. Please see "Compensation Discussion and Analysis-Components of 2016 Executive Compensation-Performance Incentive Compensation" for additional information.

(2)

The amounts reflected in this column for 2016 relate to awards granted by the Compensation Committee pursuant to the 2016 Incentive Plan. The NEOs received cash payouts under the 2016 Incentive Plan for the first, second and third Quarterly Periods. Pursuant to the Settlement Agreement, the Company and the NEOs agreed in December 2016 that the NEOs would waive their claims related to the 2016 Incentive Plan for the fourth Quarterly Period in exchange for participation in the Company’s KEIP. As a result, none of the NEOs was entitled to any payments with respect the fourth Quarterly Period or to any Annual True-Up payment pursuant to the 2016 Incentive Plan. Please see "Compensation Discussion and Analysis-Components of 2016 Executive Compensation-Performance Incentive Compensation" and "-2017 Compensation Arrangements" for additional information.


(3)	The following table provides detail for the All Other Compensation column for each of the NEOs for 2016. Please see "Compensation Discussion and Analysis-Other Program Components" for a brief discussion of these items.

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	Mr. Welch		Mr. Beer		Ms. Jaubert		Mr. Seilhan		Mr. Toothman
Company 401(k) match	$	9,000	$	9,000	$	9,000	$	9,000	$	9,000
Annual dues for club memberships	11,919		—		—		—		—
	$	20,919	$	9,000	$	9,000	$	9,000	$	9,000

(4)

The amounts reflected in this column are supplemental and are not required by the SEC’s compensation disclosure rules. As described in the "Compensation Discussion and Analysis," TDC represents total direct compensation awarded by our Compensation Committee for service with respect to a given fiscal year. TDC reported in this column includes, for each NEO, (a) the annual base salary rate for the given year, (b) the amount in the "Non-Equity Incentive Plan Compensation" column for the given year, and (c) the grant date fair value of the long-term incentive award of restricted stock granted in the following fiscal year for performance in the given year. Because we suspended our long-term incentive award program for 2015 and 2016, there were no annual restricted stock or other long-term incentive awards granted in 2016 with respect to 2015 performance or to date in 2017 with respect to 2016 performance. Hence, the TDC column for 2016 reflects only base salary and payments under the 2016 Incentive Plan, including payments made thereunder to Mr. Welch in the form of shares of our common stock. We believe TDC more accurately represents the compensation decisions made by the Compensation Committee with respect to performance for a given fiscal year.

Grants of Plan Based Awards

The following table discloses information concerning each grant of awards in 2016 under the Stock Incentive Plan to the NEOs. It also discloses the potential cash payouts under our 2016 Incentive Plan with respect to awards granted in 2016. For more information about these awards, please read the section above titled "Compensation Discussion and Analysis-Components of 2016 Executive Compensation-Performance Incentive Compensation."



GRANTS OF PLAN BASED AWARDS TABLE FOR THE YEAR ENDED DECEMBER 31, 2016
		Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)			All Other Stock Awards: Number of Shares of Stock or Units(#)(3)	Grant Date Fair Value of Stock and Option Awards($)(4)
Name	Grant Date	Threshold($)	Target ($)	Maximum($)		Grant Date Fair Value of Stock and Option Awards($)(4)
David H. Welch	05/06/16	—	—	—	3,944	$	28,988
	08/05/16	—	—	—	12,256	125,318
	11/07/16	—	—	—	3,462	13,952
		1,316,250(2)	2,632,500(2)	3,948,750(2)	—	—

Kenneth H. Beer	—	570,000	1,140,000	1,710,000	—	—

Lisa S. Jaubert	—	412,500	825,000	1,237,500	—	—

Keith A. Seilhan	—	315,000	630,000	945,000	—	—

Richard Toothman, Jr.	—	285,000	570,000	855,000	—	—

(1)

These columns show the range of possible Annual Period award opportunities granted by the Compensation Committee pursuant to the 2016 Incentive Plan, as discussed above in the section entitled "Compensation Discussion and Analysis-Components of 2016 Executive Compensation-Performance Incentive Compensation." Award opportunities for each Quarterly Period are equal to 25% of the Annual Period award opportunity for each NEO. If the Company’s performance does not meet the threshold performance hurdle for a Quarterly Period, then the payout for that Quarterly Period will be zero. The amounts shown in the "Threshold" column reflect a payout of 50% of the target Annual Period award opportunity; the amounts shown in the "Target" column reflect a payout of 100% of the target Annual Period award opportunity; and the amounts shown in the "Maximum" column reflect the highest possible payout of 150% of target Annual Period award opportunity. The Compensation Committee determined that the Company’s performance with respect to the applicable performance goals exceeded the minimum performance level for the first, second and third Quarterly Periods and, consequently, the actual payouts made under the 2016 Incentive Plan with respect to those Quarterly Periods are reflected in the "Non-Equity Incentive Plan Compensation" and "Stock Awards" columns of the Summary Compensation Table for 2016, as applicable. Pursuant to the Settlement Agreement, the Company and the NEOs agreed in December 2016 that the NEOs would waive their claims related to the 2016 Incentive Plan for the fourth Quarterly Period in exchange for participation in the Company’s KEIP. As a result, none of the NEOs was entitled to any payments with respect the fourth Quarterly Period or to any Annual True-Up

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payment pursuant to the 2016 Incentive Plan. Please see "Compensation Discussion and Analysis-Components of 2016 Executive Compensation-Performance Incentive Compensation" and "-2017 Compensation Arrangements" for additional information.

(2)

Represents 90% of Mr. Welch’s total possible threshold, target and maximum Annual Period award opportunities under the 2016 Incentive Plan. The remaining 10% of Mr. Welch’s earned award opportunities under the 2016 Incentive Plan were payable in shares of the Company’s common stock issued under the Stock Incentive Plan, which are reported in the "Stock Awards" column of the Summary Compensation Table and in the last two columns of this table.


(3)	Reflects the actual shares of stock issued under the Stock Incentive Plan in payment of the 10% portion of Mr. Welch’s earned award opportunities under the 2016 Incentive Plan for the first, second and third Quarterly Periods, as adjusted for our 1-for-10 reverse stock split (with respect to the shares of stock issued on May 6, 2016).


(4)	Calculated in accordance with FASB ASC Topic 718, determined without regard to possible forfeitures, as described in footnote 1 to the Summary Compensation Table.

Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table

The following narrative provides additional information about the various compensation plans, programs and policies reflected in the Summary Compensation Table and the Grants of Plan Based Awards Table for the year ended December 31, 2016.

Employment-Related Agreements with NEOs

Certain terms governing the employment and compensation of Messrs. Welch, Beer and Toothman during 2016 were set forth in individual employment agreements. Pursuant to the Settlement Agreement, we terminated Mr. Beer’s employment agreement and entered into amended employment agreements with Messrs. Welch and Toothman. Please see "Compensation Discussion and Analysis-2017 Compensation Arrangements" and "Potential Payments Upon Involuntary Termination or Change of Control" for additional information. We do not maintain employment agreements with any other NEOs.

Salary and Annual Incentive Compensation in Proportion to Total Compensation

Because we suspended the historical annual cash incentive compensation award and long-term equity incentive compensation programs for 2016 and instead implemented in the 2016 Incentive Plan, actual TDC for our NEOs was comprised only of base salary and earned award opportunities paid out for the first, second and third Quarterly Periods under the 2016 Incentive Plan, including the 10% portion of such earned amounts that were paid to Mr. Welch in the form of shares of our common stock (which is reported in the “Stock Awards” column of the Summary Compensation Table for 2016).

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Outstanding Equity Awards at Fiscal Year-End

The following table contains information concerning the number and value of outstanding and unexercised options as well as the number and value of unvested restricted stock awards as of December 31, 2016, which have been adjusted as applicable to reflect our 1-for-10 reverse stock split that occurred in June 2016.



OUTSTANDING EQUITY AWARDS AT DECEMBER 31, 2016
	Option Awards					Stock Awards
Name	Option Grant Date	Number of Securities Underlying Unexercised Options (#) Exercisable(1)	Number of Securities Underlying Unexercised Options (#) Unexercisable	Option Exercise Price($)	Option Expiration Date	Stock Award Grant Date	Number of Shares or Units of Stock That Have Not Vested(#)	Market Value of Shares or Units of Stock That Have Not Vested($)(2)
David H. Welch	1/9/2007	1,500	—	331.90	1/9/2017
	1/15/2008	2,500	—	446.70	1/15/2018
	1/15/2009	2,000	—	100.50	1/15/2019
	2/17/2009	2,947	—	69.70	2/17/2019
						3/1/2014	4,111 (3)	29,394
						3/1/2015	16,725 (4)	119,584
Kenneth H. Beer	1/9/2007	1,000	—	331.90	1/9/2017
	1/15/2008	1,500	—	446.70	1/15/2018
	1/15/2009	1,500	—	100.50	1/15/2019
						3/1/2014	1,539 (3)	11,004
						3/1/2015	5,047 (4)	36,086
Lisa S. Jaubert	—	—	—	—	—
						3/1/2014	695 (3)	4,969
						3/1/2015	2,940 (4)	21,021
Keith A. Seilhan	—	—	—	—	—
						3/1/2014	515 (3)	3,682
						3/1/2015	2,621 (4)	18,740
Richard L. Toothman, Jr.	—	—	—	—	—
						3/1/2014	593(3)	4,240
						3/1/2015	2,535(4)	18,125


(1)	All outstanding stock options were fully vested as of December 31, 2016. Generally, stock options vested in substantially equal annual installments over a five-year period.


(2)	The market value shown was determined by multiplying the number of unvested shares of stock by $7.15, which was the closing market price of our common stock on December 30, 2016 (which was the last trading day of fiscal 2016).


(3)	The restrictions on the total number of shares of restricted stock granted on March 1, 2014 lapsed or will lapse as follows: (a) with respect to one-third of the total shares on January 15, 2015, (b) with respect to one-third of the total shares on January 15, 2016, and (c) with respect to the remaining one-third of the total shares on January 15, 2017.


(4)	The restrictions on the total number of shares of restricted stock granted on March 1, 2015 lapsed or will lapse as follows: (a) with respect to one-third of the total shares on January 15, 2016, (b) with respect to one-third of the total shares on January 15, 2017, and (c) with respect to the remaining one-third of the total shares on January 15, 2018.

Option Exercises and Stock Vested

The following table sets forth information regarding the number of stock awards vested, and the related value received during 2016 for the NEOs. There were no stock option exercises during 2016. All values realized were calculated by using the market value of our stock on the vesting date for the award, which was the average of the high and low price of our stock on the vesting date (or, if the vesting date was not a trading day, on the last trading day preceding the vesting date), and reflect applicable adjustments due to the 1-for-10 reverse stock split that occurred in June 2016.

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OPTION EXERCISES AND STOCK VESTED TABLE FOR THE YEAR ENDED DECEMBER 31, 2016
	Stock Awards
Name	Number of Shares Acquired on Vesting(#)	Value Realized on Vesting($)
David H. Welch	37,313	$	651,485
Kenneth H. Beer	6,066	166,068
Lisa S. Jaubert	2,465	67,504
Keith A. Seilhan	2,517	68,941
Richard L. Toothman, Jr.	2,388	65,391

Nonqualified Deferred Compensation

The following table sets forth information regarding nonqualified deferred compensation during 2016 for the NEOs.



NONQUALIFIED DEFERRED COMPENSATION TABLE FOR THE YEAR ENDED DECEMBER 31, 2016
Name	Executive Contributions in Last FY($)	Aggregate Earnings (Loss) in Last FY($)		Aggregate Balance at Last FYE($)(1)
David H. Welch	—	$	200,281	$	4,148,673
Kenneth H. Beer	—	77,439		1,167,029
Lisa S. Jaubert	—	—		—
Keith A. Seilhan	—	—		—
Richard L. Toothman, Jr.	—	—		—


(1)	The following portions of the aggregate balance amounts for each of the NEOs were reported as compensation to the officer in the Summary Compensation Table in previous fiscal years: Mr. Welch -$526,420 for the year ended December 31, 2010 and $208,391 for the year ended December 31, 2009; and Mr. Beer -$35,333 for the year ended December 31, 2009 and $168,729 for the year ended December 31, 2014.

Our Deferred Compensation Plan provides eligible executives and other highly compensated individuals with the option to defer up to 100% of their base salary and 100% of their annual incentive award for a given calendar year. Deferral elections are made separately for salary and bonus not later than December 31 for amounts to be earned in the following year. Currently, Messrs. Welch and Beer are the only NEOs who participate in the Deferred Compensation Plan and neither elected to defer any amounts to the plan for 2016. We expect to continue to maintain the Deferred Compensation Plan following our emergence from bankruptcy.

The Deferred Compensation Plan previously provided that the Compensation Committee may, at its discretion, match all or a portion of the participant’s deferral based upon a percentage determined by the Board. In addition, the Board may elect to make discretionary profit sharing contributions to participants in the Deferred Compensation Plan. Since the inception of the Deferred Compensation Plan, we have not made matching or profit sharing contributions. In connection with our entry into the Settlement Agreement, we adopted an amendment to the Deferred Compensation Plan that removed our ability to make matching contributions under the Deferred Compensation Plan.

All participant contributions to the Deferred Compensation Plan and investment returns on those contributions are fully vested. Distributions from the Deferred Compensation Plan are only made upon a separation of service and will be made as a lump-sum cash payment or in monthly installments over up to ten years, based on the participant’s election and subject to the six-month delay of distributions imposed on certain of our key employees by Section 409A of the Code. The amounts held under the Deferred Compensation Plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. Investment options under the plan are identical to the investment options available to participants in our 401(k) Plan. Both the Deferred Compensation Plan and the 401(k) Plan utilize a mutual fund investment window that enables participants to elect a wide variety of mutual funds. Participants may change their investment elections daily. The investment funds and rate of return for the year ended December 31, 2016 for the investment options elected by the NEOs who participated in the Deferred Compensation Plan during 2016 are as follows:


•	David H. Welch - Stock investments included Fidelity International Discovery, Fidelity Retirement Money Market Fund, Fidelity Retirement Government Money Market Fund and Fidelity New Markets, Inc., with a combined rate of return of 5.1% for the year ended December 31, 2016.

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•	Kenneth H. Beer - Stock investments included Fidelity Leveraged Co. Stock Fund, Fidelity Diversified International Fund, Fidelity Small Cap Stock Fund, Fidelity 500 Index PR, Fidelity Emerging Asia Fund and Fidelity Emerging Markets Fund with a combined rate of return of 7.1% for the year ended December 31, 2016.

Potential Payments Upon Termination or Change of Control

As described above in the "Compensation Discussion and Analysis," pursuant to the terms of the Settlement Agreement, in December 2016, we took action to terminate or otherwise modify certain existing severance and change of control arrangements with our NEOs and adopted a new Executive Severance Plan. Because the arrangements adopted and entered into in December 2016 have been approved by the Bankruptcy Court and have become effective, we describe and quantify the payments and benefits thereunder below.

Employment Agreements

We currently have employment agreements with two of our NEOs, Messrs. Welch and Toothman. We do not maintain employment agreements with any other NEOs, as Mr. Beer’s employment agreement was terminated pursuant to the Settlement Agreement.

On January 12, 2006, we initially entered into an employment agreement with Mr. David H. Welch (the "Welch Agreement"). The Welch Agreement was amended effective as of December 2, 2008 to comply with Section 409A of the Code and was further amended on December 13, 2016 pursuant to the terms of the Settlement Agreement to remove certain provisions regarding bonus, equity vesting, severance and tax gross-up payments. As a result of the termination of Mr. Beer’s agreement and the amendment to Mr. Welch’s agreement, Messrs. Welch and Beer have agreed to the elimination of all rights to any potential Section 4999 gross-up payments, and none of our NEOs currently is entitled to any potential gross up payment. Under the Welch Agreement, as amended, Mr. Welch is eligible to participate in the Executive Severance Plan pursuant to its terms, as described below.

On August 10, 2016, we entered into a letter agreement with Mr. Richard L. Toothman, Jr. (the "Toothman Agreement"). The Toothman Agreement was amended on December 13, 2016 pursuant to the terms of the Settlement Agreement to provide that Mr. Toothman will also be a participant in the Executive Severance Plan. In addition, the Toothman Agreement was amended to reduce the severance benefits payable upon his "Qualifying Termination" of employment following an "Appalachian Disposition" from 2.99 times his base salary to 2 times his base salary. These benefits will offset any benefits provided to Mr. Toothman pursuant to the Executive Severance Plan and are not in addition to any Executive Severance Plan benefits to which he may become entitled. For purposes of the Toothman Agreement:


•	An "Appalachia Disposition" generally means the sale or other disposition of all or substantially all of the Company’s oil and gas business in the Appalachia regions of Pennsylvania and West Virginia (subject to certain exclusions).


•	A "Qualifying Termination" means:


◦	any termination of Mr. Toothman’s employment by us during the one year period following an Appalachia Disposition (the "Qualifying Termination Period") other than for "cause", and

◦

any termination of Mr. Toothman’s employment by him during the Qualifying Termination Period for "good reason." However, in order for a termination of employment to be for "good reason," Mr. Toothman must first give us written notice of the "good reason" event within 30 days of the initial existence of the "good reason" event, and we shall then have 30 days from the receipt of such notice to remedy the event. If we fail to timely remedy the event, then Mr. Toothman may terminate his employment for "good reason" in the seven day period following our failure to remedy the event. A termination of employment by Mr. Toothman for "good reason" will be deemed to be within the Qualifying Termination Period if the initial existence of the "good reason" event occurs within the applicable Qualifying Termination Period.

Executive Severance Plan

The Executive Severance Plan was established to provide financial security to our executives, including our NEOs, upon certain terminations of employment. The Compensation Committee is responsible for administering the Executive Severance Plan. Pursuant to the Settlement Agreement, all of the NEOs are participants in the Executive Severance Plan. Our NEOs who previously participated in the Company’s Executive Change of Control and Severance Plan (the "COC/Severance Plan") waived their right to receive change of control payments under such plan that could have been triggered upon consummation of the plan of reorganization (and such plan was terminated), and in exchange therefor, became participants in the Executive Severance Plan pursuant to the Settlement Agreement.

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Pursuant to the Executive Severance Plan, if an executive, including a NEO, incurs an "involuntary termination" (as defined below) of employment, the executive will receive the following:


•	Any earned but unpaid portion of base salary up to the date of termination.


•	A lump sum cash severance payment of: (i) 1.5 times annual base salary plus 1.0 times accrued bonus (for Mr. Welch), (ii) 1.25 times annual base salary plus 1.0 times accrued bonus (for Mr. Beer), and (iii) 1.0 times annual base salary for all other NEOs.


•	Outplacement services, the duration and costs for which are to be determined by the then prevailing practice of the Human Resources Department and which, in no event, may exceed the amount equal to 5% of the annual base salary of the executive;


•	The continuation of health benefit coverage for the executive and, where applicable, his or her eligible dependents for the six-month period following the date of the "involuntary termination," at a cost to the executive that is equal to the cost for an active employee for similar coverage.


•	Accelerated vesting of the next tranche of any unvested, time-based equity award held by the executive that would otherwise have vested but for the "involuntary termination."

The Executive Severance Plan may not be amended or terminated in a manner which adversely affects the benefits or potential rights to benefits of any executive without such executive’s consent prior to the adoption of a replacement plan. The Executive Severance Plan also requires that an executive sign a general release of claims within 45 days of an "involuntary termination" in order to receive the applicable payments and benefits.

For purposes of the Executive Severance Plan and, as applicable the employment agreements of Mr. Welch and Mr. Toothman:


•	An "involuntary termination" means any termination of an executive’s employment by us other than for "cause" or a termination by the executive for a "good reason."


•	"cause" means any termination of an executive’s employment by reason of the executive’s willful and continued failure to perform substantially their duties after written notice of such failure has been given to the executive, or the willful engaging by the executive in conduct that is materially injurious to the Company, monetarily or otherwise.


•	"good reason" means the occurrence (without an executive’s express written consent) of any one of the following acts by us:


◦	a material reduction in the executive’s annual base salary (except for certain across-the-board salary reductions);


◦	a material diminution in the authority, duties or responsibilities of the executive (except for a change resulting from our no longer being a public company);


◦	a requirement that the executive transfer to a work location that is more than 50 miles from such executive’s principal work location that materially increases the executive’s commute; or


◦	failure to adopt a new severance plan replacing the Executive Severance Plan within 180 days after the effective date of our plan of reorganization under Chapter 11 of the Bankruptcy Code.

The Executive Severance Plan provides that the executive’s right to terminate employment for “good reason” shall not be affected by the executive’s incapacity due to physical or mental illness.

Payments Made Upon Termination Generally

Regardless of the manner in which an executive’s (including a NEO) employment terminates, he or she is entitled to receive amounts earned during his or her employment. These amounts include:


•	non-equity compensation earned during the fiscal year;


•	amounts contributed pursuant to our Deferred Compensation Plan;

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•	unused vacation pay; and


•	amounts accrued and vested through our 401(k) Plan.

Upon termination in the event of death or disability, our executives, including our NEOs, receive the same benefits as are provided to our employees generally on a nondiscriminatory basis (including 401(k) matching contributions for the year of death or disability, group term life insurance benefits and long-term disability benefits). However the maximum benefit provided under our long-term disability policy to our NEOs (and other executives) is $15,000 per month (or 66 2⁄3% of salary if less). This monthly maximum is higher than the monthly maximum established for other employees.

Quantification of Potential Payments Upon Termination or Change of Control

The table below reflects the amount of compensation to each of the NEOs in the event of termination of such executive’s employment, or a Change of Control, as applicable. The amount of compensation payable to each NEO upon an “involuntary termination” is shown below, with additional amounts shown for Mr. Toothman upon a Qualifying Termination following an Appalachia Disposition as provided in the Toothman Agreement.

The following assumptions were used in determining the amounts below in the Potential Payment Upon Termination or Change of Control Table:


•	All terminations (including the Appalachia Disposition, as applicable) would be effective as of December 31, 2016.


•	Payments are calculated pursuant to the terms of the Executive Severance Plan and the modifications to the employment agreements established pursuant to the Settlement Agreement in December 2016.


•	Mr. Welch’s employment agreement requires us to provide him with one year’s prior written notice in order to terminate his employment. The amounts reported in the table below does not include any compensation or benefits that would be paid or provided to Mr. Welch during the one-year period from the date notice of termination of his employment was provided to the date of such termination.


•	The closing share price of our common stock as of December 30, 2016 (the last trading day of fiscal 2016) was $7.15.

•

The actual amounts to be paid can only be determined at the time of such executive’s actual separation from employment. The accrued bonus, for example (as applicable to Mr. Welch and Mr. Beer), is a pro rata share of the Annual Period award opportunity under the 2016 Incentive Plan up to the date of termination at the then projected year-end rate of payout in an amount, if any, as determined by the Compensation Committee in its sole discretion.


•	Outplacement services are not to exceed an amount equal to 5% of the annual base salary of the executive.


•	Vacation pay assumes the executive has not used any vacation days and is being paid for all unused days.

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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL TABLE
Name	Benefit	Involuntary Termination		Involuntary Termination Occurring Following an Appalachia Disposition
David H. Welch	Severance (1)	$	975,000	—
	Pro rata incentive compensation (2)	2,149,226		—
	Outplacement (3)	32,500		—
	Health and welfare benefits (4)	8,626		—
	Stock options and restricted stock - accelerated vesting (5)	148,970		—
	Vacation /Sick pay (6)	75,000		—
	Total	$	3,389,322	—


Kenneth H. Beer	Severance (1)	$	475,000	—
	Pro rata incentive compensation (2)	857,850		—
	Outplacement (3)	19,000		—
	Health and welfare benefits (4)	8,626		—
	Stock options and restricted stock - accelerated vesting (5)	47,083		—
	Vacation /Sick pay (6)	43,846		—
	Total	$	1,451,405	—


Lisa S. Jaubert	Severance (1)	$	300,000	—
	Outplacement (3)	15,000		—
	Health and welfare benefits (4)	8,626		—
	Stock options and restricted stock - accelerated vesting (5)	25,983		—
	Vacation/Sick pay (6)	34,615		—
	Total	$	384,224	—


Keith A. Seilhan	Severance (1)	$	320,000	—
	Outplacement (3)	16,000		—
	Health and welfare benefits (4)	12,942		—
	Stock options and restricted stock - accelerated vesting (5)	22,408		—
	Vacation/Sick pay (6)	36,923		—
	Total	$	408,273


Richard L. Toothman, Jr.	Severance (1)	$	300,000	$	600,000
	Outplacement (3)	15,000		15,000
	Health and welfare benefits (4)	8,626		8,626
	Stock options and restricted stock - accelerated vesting (5)	22,365		22,365
	Vacation/Sick pay (6)	34,615		34,615
	Total	$	380,606	$	680,606


(1)	Severance amounts are calculated by multiplying (a) Mr. Welch’s base salary by 1.5, (b) Mr. Beer’s salary by 1.25 and (c) the other NEOs’ base salaries by 1.0. For 2016, Mr. Welch’s base salary was $650,000, Mr. Beer’s base salary was $380,000, Ms. Jaubert’s base salary was $300,000, Mr. Seilhan’s base salary was $320,000 and Mr. Toothman’s base salary was $300,000.

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For Mr. Toothman’s severance following an Appalachian Disposition, the severance amount was calculated by multiplying Mr. Toothman’s base salary by 2.0.

(2)

These amounts reflect the total amount actually paid to each NEO for 2016 performance under the 2016 Incentive Plan prior to such plan’s termination, which we believe is reflective of the projected year-end rate of payout as of December 31, 2016. These amounts are also reported for 2016 in the "Non-Equity Incentive Plan Compensation" column of the Summary Compensation Table and, in the case of Mr. Welch, also in the "Stock Awards" column of the Summary Compensation Table.


(3)	The amounts reported for each executive’s outplacement services assume that the maximum amount of 5% of salary was paid.


(4)	The amounts reported above represent the portion of employee health insurance premiums covered by us for each NEO per month multiplied by 6 months.

(5)

The amounts reported above reflect accelerated vesting of the tranche of unvested stock options and restricted stock that would next vest following the date of termination. None of the NEOs held unvested stock options as of December 31, 2016. The restricted stock portion of the amounts above are calculated by multiplying the number of shares of restricted stock that would vest on the next vesting date after December 31, 2016 by the fair market value of the stock on December 30, 2016 (the last trading day of 2016), which was $7.15. The number of restricted shares that would next vest for each NEO following a termination on December 31, 2016 was as follows:


•	Mr. Welch - 20,836 shares,


•	Mr. Beer - 6,586 shares,


•	Ms. Jaubert - 3,635 shares,


•	Mr. Seilhan - 3,136 shares, and


•	Mr. Toothman -3,128 shares.


(6)	The amounts reported above for vacation and sick pay were calculated by using the NEO’s base salary divided by 2080 hours, multiplied by 240 hours.

2016 DIRECTOR COMPENSATION

Elements of Director Compensation

Each of our directors who is not an officer or employee of our Company or any of its subsidiaries (a "nonemployee director") was paid an annual retainer of $195,000 for their service in 2016 in lieu of fees based on the number of meetings attended. The annual retainer was paid in four equal quarterly payments of $48,750 each, with $43,875 payable in cash and $4,875, or 10%, to be paid in stock under the Company’s Stock Incentive Plan. Additionally, the individuals serving in the following roles received an additional annual cash retainer, also paid on a quarterly basis: (i) the Lead Director received $25,000, (ii) the Audit Committee Chairman received $15,000, (iii) the Compensation Committee Chairman received $10,000, (iv) the Nominating & Governance Committee Chairman received $9,000, and (v) the Reserves Committee Chairman received $9,000. The Board has also reserved the right, in its sole discretion, to provide additional compensation at a rate of not more than $1,500 per additional meeting to nonemployee directors who attend more than five meetings of the Board or more than five meetings of each committee on which he or she serves during a calendar year. The Board did not exercise this right in fiscal 2016.

For the 10% stock portion of the 2016 annual retainer, each director was awarded the following shares of stock pursuant to the Stock Incentive Plan as follows: (i) 213 shares for the first quarter, (ii) 692 shares for the second quarter, (iii) 384 shares for the third quarter, and (iv) 697 shares for the fourth quarter, which shares are fully vested at the time of grant. The number of shares of stock granted was calculated by dividing $4,875 by the average closing share price of the Company's common stock for each quarter, subject to applicable withholding, and rounding up to the next whole share.

In April 2016, the independent directors of the Board appointed Mr. Lawrence as a Special Liaison of the independent directors to work with management in assessing strategic and restructuring alternatives. Mr. Lawrence received additional fees during 2016 for his role as Special Liaison, which are reflected in the "Director Compensation Table" below.

Stock Ownership and Retention Guidelines and Certain Prohibitions Related to Our Securities

The Board has adopted Stock Ownership Guidelines that apply to our nonemployee directors, who are required to meet the following ownership level by the later of May 23, 2017 or within five years of being elected to their position. All nonemployee directors are in compliance with the Stock Ownership Guidelines. Mr. Welch is subject to the Stock Ownership Guidelines applicable to our executive officers, which are described in greater detail in the “Compensation Discussion and Analysis” above.

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Individual		Multiple of Annual Retainer(1)
Nonemployee Director		5x annual retainer


(1)	In effect on January 1 of the applicable year.

Among other terms, the guidelines provide that (1) stock granted under the Company’s Stock Incentive Plan will be included in determining the stock ownership of an individual, and (2) until the applicable guideline is attained, an individual is required to retain, and not sell or otherwise dispose of, at least 75% of his or her net shares (after taxes) acquired through long-term incentive awards. The value of our stock used in determining the number of shares needed to comply with the guidelines in a given year will be the average price of our stock during August of that same calendar year. The Board may amend or terminate the Stock Ownership Guidelines in its sole discretion.

The Board has adopted a policy prohibiting any nonemployee director of the Company from hedging company stock.

Director Compensation Table

The following table discloses the cash, equity awards and other compensation earned, paid or awarded, to each of our directors during 2016.



DIRECTOR SUMMARY COMPENSATION FOR THE YEAR ENDED DECEMBER 31, 2016
Name(1)	Fees Earned or Paid in Cash($)		Stock Awards($)(2)		All Other Compensation ($)(3)		Total($)
George R. Christmas	$	139,129	$	12,229	$	1,000	$	152,358
B. J. Duplantis	138,379		12,229		—		150,608
Peter D. Kinnear	131,629		12,229		—		143,858
David T. Lawrence	131,629		12,229		697,500(4)		841,358
Robert S. Murley	131,629		12,229		—		143,858
Richard A. Pattarozzi	150,379		12,229		10,000		172,608
Donald E. Powell	131,629		12,229		—		143,858
Kay G. Priestly	142,879		12,229		—		155,108
Phyllis M. Taylor	138,379		12,229		—		150,608


(1)	David H. Welch is not included in this table as he is an officer and thus receives no compensation for his service as a director. The compensation received by Mr. Welch is shown in the Summary Compensation Table.

(2)

The values shown in this column reflect the aggregate grant date fair value of stock awards granted in fiscal 2016, computed in accordance with FASB ASC Topic 718, determined without regard to possible forfeitures. The value ultimately received by the director may or may not be equal to the values reflected above. See Note 13 to our audited financial statements for the year ended December 31, 2016 for a complete description of the valuation, including the assumptions used. Each director received awards during fiscal 2016 as follows: (i) 213 shares at $10.60 per share, (ii) 692 shares at $12.14 per share, and (iii) 384 shares at $4.10 per share. In addition, for services related to the fourth quarter of fiscal 2016, each director received 697 shares at $6.80 per share, which are not included in the table above because such shares were granted in January 2017. None of our nonemployee directors held any unvested restricted stock at December 31, 2016.

(3)

The values shown in this column (other than with respect to Mr. Lawrence) consisted solely of matching charitable contributions of up $10,000 in the aggregate per calendar year per director to qualified charitable organizations. In fiscal 2016, the total matching contributions by our Company for all directors was $11,000, and contributions were made to the following organizations: Aquia Episcopal Church, The Good Shephard School, St. Bede Academy, National WWII Museum, University of Illinois Foundation and Army War College Foundation.


(4)	In April 2016, Mr. Lawrence was named Special Liaison of the independent directors to work together with the management of the Company to help with assessing strategic alternatives and restructuring alternatives for the Company. This represents the amount of compensation that Mr. Lawrence received with respect to such services provided.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Directors, Management and Certain Beneficial Holders

The following table sets forth certain information regarding beneficial ownership of common stock as of February 21, 2017 (unless otherwise indicated) of (1) each person known by us to own beneficially more than 5% of our outstanding common stock, (2) our Named Executive Officers (as defined herein), (3) each of our directors and director nominees, and (4) all of our executive officers and directors as a group. Unless otherwise indicated, each of the persons below has sole voting and investment power with respect to the shares beneficially owned by such person.



Name and Address of Beneficial Owner(1)	Amount and Nature of Beneficial Ownership(2)	Percent of Class(3)
Thomas A. Satterfield, Jr.(4)	459,370	8.1%
Raymond T. Hyer(5)	401,905	7.1%
David H. Welch	87,750	1.5%
Kenneth H. Beer	24,660	*
Lisa S. Jaubert	5,603	*
Keith A. Seilhan	6,332	*
Richard L. Toothman, Jr.	6,318	*
George R. Christmas	6,468	*
B. J. Duplantis	6,556	*
Peter D. Kinnear	8,958	*
David T. Lawrence	2,592	*
Robert S. Murley	1,156	*
Richard A. Pattarozzi	5,970	*
Donald E. Powell	7,279	*
Kay G. Priestly	5,317	*
Phyllis M. Taylor	7,700	*
Executive officers and directors as a group (consisting of 18 persons)	205,106	3.6%


*	Less than 1%.


(1)	Unless otherwise noted, the address for each beneficial owner is c/o Stone Energy Corporation, 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508.

(2)

Under the regulations of the SEC, shares are deemed to be "beneficially owned" by a person if he or she directly or indirectly has or shares the power to vote or dispose of, or to direct the voting or disposition of, such shares, whether or not he or she has any pecuniary interest in such shares, or if he or she has the right to acquire the power to vote or dispose of such shares within 60 days, including any right to acquire such power through the exercise of any option, warrant or right. The shares beneficially owned by (a) Mr. Welch include 7,447 shares, (b) Mr. Beer include 3,000 shares, and (c) the executive officers and directors as a group include 10,447 shares, that may be acquired by such persons within 60 days through the exercise of stock options.


(3)	Based on total shares issued and outstanding of 5,679,765 as of February 21, 2017. Based on the number of shares owned and acquirable within 60 days of February 21, 2017.

(4)

Thomas A. Satterfield, Jr.'s address is 2609 Caldwell Mill Lane, Birmingham, Alabama 35243. The number of shares held is based on information included in a Schedule 13G filed on January 24, 2017. Thomas A. Satterfield, Jr. has sole voting power as to 23,900 shares, shared voting power as to 435,470 shares, sole dispositive power as to 23,900 shares and shared dispositive power as to 435,470 shares.


(5)	Raymond T. Hyer's address is 4161 East 7th Avenue, Tampa, Florida 33675. The number of shares held is based on information included in a Schedule 13D filed on December 19, 2016. Raymond T. Hyer has sole voting power as to 250,051 shares, shared voting power as to 151,854 shares, sole dispositive power as to 250,051 shares and shared dispositive power as to 151,854 shares.

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Equity Compensation Plan Information

The following table provides information regarding the shares of our common stock that may be issued under our existing equity compensation plans, with the Stock Incentive Plan being the only active equity plan under which the Company may grant equity compensation awards as of December 31, 2016. As of December 31, 2016, there were 81,090 shares of restricted stock outstanding under to the Stock Incentive Plan.



Equity Compensation Plan Information as of December 31, 2016
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights(a)	Weighted- average exercise price of outstanding options, warrants and rights(b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column(a))(c)
Equity compensation plans approved by security holders	12,947(1)	$	245.13	237,062
Equity compensation plans not approved by security holders (2)	—	—		—
Total	12,947	$	245.13	237,062


(1)	Weighted average term of outstanding options is 1.4 years.


(2)	No equity compensation plans have been adopted without approval by security holders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Policies and Procedures

The Nominating & Governance Committee Charter provides that the Nominating & Governance Committee periodically reviews all transactions that would require disclosure under Item 404(a) of Regulation S-K (each, a "Related Person Transaction") and makes a recommendation to the Board regarding the initial authorization or ratification of any such transaction. In accordance with such policies and procedures, each officer and director must complete a directors and officers questionnaire each year that solicits information concerning transactions with related persons. Additionally, at least quarterly, the Nominating & Governance Committee asks each director whether any issues have arisen concerning independence, transactions with related persons or conflicts of interest. To the extent that a transaction or a possible transaction with a related person exists, the Nominating & Governance Committee determines whether the transaction should be approved or ratified and makes its recommendation to the Board. In determining whether or not to recommend the initial approval or ratification of a Related Person Transaction, the Nominating & Governance Committee considers all of the relevant facts and circumstances available to the committee, including (if applicable) but not limited to:


•	whether there is an appropriate business justification for the transaction;


•	the benefits that accrue to Stone as a result of the transaction;


•	the terms available to unrelated third parties entering into similar transactions;


•	the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director is a partner, stockholder or executive officer);


•	the availability of other sources for comparable products or services;


•	whether it is a single transaction or a series of ongoing, related transactions; and


•	whether entering into the transaction would be consistent with our Code of Business Conduct and Ethics.

In the event that the Board considers ratification of a Related Person Transaction and determines not to so ratify, management makes all reasonable efforts to cancel or annul such transaction.

Related Party Transactions

There were no related party transactions for the year ended December 31, 2016.

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Director Independence Determinations

Our Corporate Governance Guidelines provide that a majority of our Board will consist of independent directors. Only directors who have been determined to be independent serve on our Audit Committee, Compensation Committee, Nominating & Governance Committee and Reserves Committee.

Rather than adopting categorical standards, the Board assesses director independence on a case-by-case basis, in each case consistent with applicable legal requirements and the independence standards adopted by the NYSE. None of the non-management directors were disqualified from "independent" status under the objective NYSE listing standards. Based on information provided by the directors and after reviewing all relationships each director has with Stone, including charitable contributions we make to organizations where our directors serve as board members, the Board has affirmatively determined that none of its non-management directors have a material relationship with Stone and therefore each is independent as defined by the current listing standards of the NYSE. In making its independence determinations, the Board took into account the relationships and recommendations of the Nominating & Governance Committee as described below. Mr. Welch, our Chairman, President and CEO, is not considered by the Board to be an independent director because of his employment with us.

The Nominating & Governance Committee has considered Donald E. Powell’s ownership of approximately $400,000 in aggregate principal amount of our debt securities that were acquired in the secondary market, and made a determination that such ownership did not preclude the independence of Mr. Powell because Mr. Powell does not receive any benefit with respect to such debt securities that is not shared on a pro rata basis with all other holders of our debt securities.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Preapproval Policies and Procedures

The Audit Committee has the sole authority to appoint or replace the independent registered public accounting firm (subject, if applicable, to stockholder ratification), and approves all audit engagement fees and terms and all significant non-audit engagements with the independent registered public accounting firm. The Audit Committee has established policies and procedures regarding pre-approval of all services provided by the independent registered public accounting firm. At the beginning of the fiscal year, the Audit Committee pre-approves the engagement of the independent registered public accounting firm to provide audit services based on fee estimates. The Audit Committee also pre-approves proposed audit-related services, tax services and other permissible services, based on specified project and service details, fee estimates, and aggregate fee limits for each service category. The Audit Committee pre-approved all services provided by the independent registered public accounting firm in fiscal 2016. The Audit Committee receives a report at each meeting on the status of services provided or to be provided by the independent registered public accounting firm and the related fees.

Fees paid to Independent Accounting Firm

Ernst & Young LLP has served as our independent registered public accounting firm and audited our consolidated financial statements beginning with the fiscal year ended December 31, 2002. We are advised that no member of Ernst & Young LLP has any direct or material indirect financial interest in Stone or, during the past three years, has had any connection with us in the capacity of promoter, underwriter, voting trustee, director, officer or employee. Set forth below are the aggregate fees billed by Ernst & Young LLP, the independent registered public accounting firm, for each of the last two fiscal years:



	2015		2016
Audit Fees(1)	$	645,375	$	640,000
Audit-Related Fees	—		—
Tax Fees(2)	77,180		180,204
All Other Fees	—		—
Total	$	722,555	$	820,204


(1)	Audit Fees represent the aggregate fees billed for professional services provided in connection with the audit of our financial statements and internal control over financial reporting, review of our quarterly financial statements and audit services provided in connection with other statutory or regulatory filings.


(2)	Tax Fees represent the aggregate fees billed for professional services provided in connection with tax return preparation and review and tax consulting.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements:

The following consolidated financial statements, notes to the consolidated financial statements and the Report of Independent Registered Public Accounting Firm thereon are included beginning on page F-1 of this Form 10-K:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheet as of December 31, 2016 and 2015

Consolidated Statement of Operations for the three years ended December 31, 2016, 2015 and 2014

Consolidated Statement of Comprehensive Income (Loss) for the three years ended December 31, 2016, 2015 and 2014

Consolidated Statement of Cash Flows for the three years ended December 31, 2016, 2015 and 2014

Consolidated Statement of Changes in Stockholders’ Equity for the three years ended December 31, 2016, 2015 and 2014

Notes to the Consolidated Financial Statements

2. Financial Statement Schedules:

All schedules are omitted because the required information is inapplicable or the information is presented in the consolidated financial statements or the notes thereto.

3. Exhibits:



2.1		Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed February 15, 2017 (File No. 001-12074)).
3.1		Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (File No.001-12074)).
3.2		Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-12074)).
4.1		Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).
4.2		Senior Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).
4.3		First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).
4.4		Indenture related to the 1 3⁄4% Senior Convertible Notes due 2017, dated as of March 6, 2012, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A., as trustee (including form of 1 3⁄4% Senior Convertible Senior Note due 2017) (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).
4.5		Second Supplemental Indenture, dated as of November 8, 2012, to the Indenture, dated as of January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed November 8, 2012 (File No. 001-12074)).
4.6		Third Supplemental Indenture, dated as of November 26, 2013, to the Indenture, dated as of January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed November 27, 2013 (File No. 001-12074)).

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4.7		First Supplemental Indenture and Guarantee, dated as of May 7, 2015, among SEO A LLC, SEO B LLC, Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A, as trustee (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-12074)).
4.8		Fourth Supplemental Indenture, dated as of May 7, 2015, among SEO A LLC, SEO B LLC, Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A, as trustee (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-12074)).
†10.1		Deferred Compensation and Disability Agreement between TSPC and E. J. Louviere dated July 16, 1981 (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
†10.2		Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015) (incorporated by reference to Exhibit 10.2 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 001-12074)).
†10.3		First Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015) (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed May 20, 2016 (File No. 001-12074)).
†10.4		Second Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015) (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (File No. 001-12074)).
†10.5		Stone Energy Corporation Revised (2005) Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.6		Stone Energy Corporation Amended and Restated Revised Annual Incentive Compensation Plan, dated November 14, 2007 (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-12074)).
†10.7		Stone Energy Corporation 2016 Performance Incentive Compensation Plan (approved March 10, 2016) (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 (File No. 001-12074)).
†10.8		Stone Energy Corporation Deferred Compensation Plan (incorporated by reference to Exhibit 4.5 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.9		Adoption Agreement between Fidelity Management Trust Company and Stone Energy Corporation for the Stone Energy Corporation Deferred Compensation Plan dated December 1, 2004 (incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.10		Letter Agreement dated May 19, 2005 between Stone Energy Corporation and Kenneth H. Beer (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2005 (File No. 001-12074)).
†10.11		Letter Agreement dated December 2, 2008 between Stone Energy Corporation and David H. Welch (incorporated by reference to Exhibit 10.8 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 001-12074)).
†10.12		Amendment to Employment Agreement dated December 13, 2016 between Stone Energy Corporation and David H. Welch (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
†10.13		Letter Agreement dated August 10, 2016 between Stone Energy Corporation and Richard L. Toothman, Jr. (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (File No. 001-12074)).
†10.14		Stone Energy Corporation Executive Change of Control and Severance Plan (as amended and restated effective December 31, 2008) (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed April 8, 2009 (File No. 001-12074)).
†10.15		Executive Claims Settlement Agreement, dated December 13, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
†10.16		Stone Energy Corporation Executive Severance Plan, dated December 13, 2016 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).

Table of Contents



†10.17		Stone Energy Corporation Key Executive Incentive Plan, dated December 13, 2016 (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
†10.18		Stone Energy Corporation Employee Change of Control Severance Plan (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed December 12, 2007 (File No. 001-12074)).
10.19		Form of Indemnification Agreement between Stone Energy Corporation and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 27, 2009 (File No. 001-12074)).
10.20		Fourth Amended and Restated Credit Agreement among Stone Energy Corporation as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, and the financial institutions named therein, dated June 24, 2014 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed June 25, 2014 (File No. 001-12074)).
10.21		Amendment No. 1 to Credit Agreement, dated as of May 1, 2015, among Stone Energy Corporation as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, and the financial institutions party to the Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-12074)).
10.22		Amendment No. 3 to the Fourth Amended and Restated Credit Agreement among Stone Energy Corporation, certain of its subsidiaries, as guarantors, and the financial institutions party thereto, dated June 14, 2016 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed June 14, 2016 (File No. 001-12074)).
10.23		Amendment No. 4 to the Fourth Amended and Restated Credit Agreement among Stone Energy Corporation, certain of its subsidiaries, as guarantors, and the financial institutions party thereto, dated December 9, 2016 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed December 9, 2016 (File No. 001-12074)).
10.24		Amended and Restated Security Agreement, dated as of August 28, 2008, among Stone Energy Corporation and the other Debtors parties hereto in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-12074)).
10.25		Amended and Restated Restructuring Support Agreement, dated December 14, 2016, by and among the Stone Parties and the Consenting Noteholders (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
10.26		Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and TH Exploration III, LLC as buyer, dated October 20, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed October 21, 2016 (File No. 001-12074)).
10.27		First Amendment to Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and TH Exploration III, LLC as buyer, dated December 9, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed December 9, 2016 (File No. 001-12074)).
10.28		Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and EQT Production Company as buyer, and EQT Corporation as buyer parent, dated February 9, 2017 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed February 10, 2017 (File No. 001-12074)).
*21.1		Subsidiaries of the Registrant.
*23.1		Consent of Independent Registered Public Accounting Firm.
*23.2		Consent of Netherland, Sewell & Associates, Inc.
*31.1		Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2		Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1		Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
*99.1		Report of Netherland, Sewell & Associates, Inc.
*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

100

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*101.LAB		XBRL Taxonomy Extension Label Linkbase Document
*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

_________________



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

101

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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:	February 23, 2017		By: /s/ David H. Welch
			David H. Welch
			President,
			Chief Executive Officer
			and Chairman of the Board

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date
/s/ David H. Welch	President, Chief Executive Officer and Chairman of the Board (principal executive officer)	February 23, 2017
David H. Welch		February 23, 2017

/s/ Kenneth H. Beer	Executive Vice President and Chief Financial Officer (principal financial officer)	February 23, 2017
Kenneth H. Beer		February 23, 2017

/s/ Karl D. Meche	Director of Accounting and Treasurer (principal accounting officer)	February 23, 2017
Karl D. Meche		February 23, 2017

/s/ George R. Christmas	Director	February 23, 2017
George R. Christmas	Director	February 23, 2017

/s/ B.J. Duplantis	Director	February 23, 2017
B.J. Duplantis	Director	February 23, 2017

/s/ Peter D. Kinnear	Director	February 23, 2017
Peter D. Kinnear	Director	February 23, 2017

/s/ David T. Lawrence	Director	February 23, 2017
David T. Lawrence	Director	February 23, 2017

/s/ Robert S. Murley	Director	February 23, 2017
Robert S. Murley	Director	February 23, 2017

/s/ Richard A. Pattarozzi	Director	February 23, 2017
Richard A. Pattarozzi	Director	February 23, 2017

/s/ Donald E. Powell	Director	February 23, 2017
Donald E. Powell	Director	February 23, 2017

/s/ Kay G. Priestly	Director	February 23, 2017
Kay G. Priestly	Director	February 23, 2017

/s/ Phyllis M. Taylor	Director	February 23, 2017
Phyllis M. Taylor	Director

102

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INDEX TO FINANCIAL STATEMENTS



Report of Independent Registered Public Accounting Firm	F-2

Consolidated Balance Sheet as December 31, 2016 and 2015	F-3

Consolidated Statement of Operations for the years ended December 31, 2016, 2015 and 2014	F-4

Consolidated Statement of Comprehensive Income (Loss) for the years ended December 31, 2016, 2015 and 2014	F-5

Consolidated Statement of Cash Flows for the years ended December 31, 2016, 2015 and 2014	F-6

Consolidated Statement of Changes in Stockholders' Equity for the years ended December 31, 2016, 2015 and 2014	F-7

Notes to Consolidated Financial Statements	F-8

F-1

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

We have audited the accompanying consolidated balance sheets of Stone Energy Corporation as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in stockholders’ equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Stone Energy Corporation as of December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements, the Company filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the "Bankruptcy Court") seeking relief under the provisions of Chapter 11 of Title 11 of the United States Bankruptcy Code to pursue a prepackaged plan of reorganization (the "Plan"). The Bankruptcy Court entered an order confirming the Plan on February 15, 2017 and the Company expects the Plan to become effective on February 28, 2017, at which point it would emerge from bankruptcy. However, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters also are described in Note 3. The consolidated financial statements do not include any adjustments that may result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Stone Energy Corporation’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 23, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 23, 2017

F-2

Table of Contents

STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED BALANCE SHEET

(In thousands of dollars)



	December 31,
Assets	2016			2015
Current assets:
Cash and cash equivalents	$	190,581		$	10,759
Accounts receivable	48,464			48,031
Fair value of derivative contracts	—			38,576
Current income tax receivable	26,086			46,174
Other current assets	10,151			6,881
Total current assets	275,282			150,421
Oil and gas properties, full cost method of accounting:
Proved	9,616,236			9,375,898
Less: accumulated depreciation, depletion and amortization	(9,178,442		)	(8,603,955		)
Net proved oil and gas properties	437,794			771,943
Unevaluated	373,720			440,043
Other property and equipment, net of accumulated depreciation of $27,418 and $27,424, respectively	26,213			29,289
Other assets, net of accumulated depreciation and amortization of $5,360 and $4,376, respectively	26,474			18,473
Total assets	$	1,139,483		$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	19,981		$	82,207
Undistributed oil and gas proceeds	15,073			5,992
Accrued interest	809			9,022
Asset retirement obligations	88,000			21,291
Current portion of long-term debt	408			—
Other current liabilities	18,602			40,712
Total current liabilities	142,873			159,224
Long-term debt	352,376			1,060,955
Asset retirement obligations	154,019			204,575
Other long-term liabilities	17,315			25,204
Total liabilities not subject to compromise	666,583			1,449,958
Liabilities subject to compromise	1,110,182			—
Total liabilities	1,776,765			1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 30,000,000 shares; issued 5,610,020 and 5,530,232 shares, respectively	56			55
Treasury stock (1,658 shares, at cost)	(860		)	(860		)
Additional paid-in capital	1,659,731			1,648,687
Accumulated deficit	(2,296,209		)	(1,705,623		)
Accumulated other comprehensive income	—			17,952
Total stockholders’ equity	(637,282		)	(39,789		)
Total liabilities and stockholders’ equity	$	1,139,483		$	1,410,169

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

F-3

Table of Contents

STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)



	Year Ended December 31,
	2016			2015			2014
Operating revenue:
Oil production	$	281,246		$	416,497		$	516,104
Natural gas production	64,601			83,509			166,494
Natural gas liquids production	28,888			32,322			85,642
Other operational income	2,657			4,369			7,951
Derivative income, net	—			7,952			19,351
Total operating revenue	377,392			544,649			795,542
Operating expenses:
Lease operating expenses	79,650			100,139			176,495
Transportation, processing and gathering expenses	27,760			58,847			64,951
Production taxes	3,148			6,877			12,151
Depreciation, depletion and amortization	220,079			281,688			340,006
Write-down of oil and gas properties	357,431			1,362,447			351,192
Accretion expense	40,229			25,988			28,411
Salaries, general and administrative expenses	58,928			69,384			66,451
Incentive compensation expense	13,475			2,242			10,361
Restructuring fees	29,597			—			—
Other operational expenses	55,453			2,360			862
Derivative expense, net	810			—			—
Total operating expenses	886,560			1,909,972			1,050,880
Loss from operations	(509,168		)	(1,365,323		)	(255,338		)
Other (income) expenses:
Interest expense	64,458			43,928			38,855
Interest income	(550		)	(580		)	(574		)
Other income	(1,439		)	(1,783		)	(2,332		)
Other expense	596			434			274
Reorganization items	10,947			—			—
Total other expenses	74,012			41,999			36,223
Loss before income taxes	(583,180		)	(1,407,322		)	(291,561		)
Provision (benefit) for income taxes:
Current	(5,674		)	(44,096		)	159
Deferred	13,080			(272,311		)	(102,177		)
Total income taxes	7,406			(316,407		)	(102,018		)
Net loss	$	(590,586	)	$	(1,090,915	)	$	(189,543	)
Basic loss per share	$	(105.63	)	$	(197.45	)	$	(35.95	)
Diluted loss per share	$	(105.63	)	$	(197.45	)	$	(35.95	)
Average shares outstanding	5,591			5,525			5,272
Average shares outstanding assuming dilution	5,591			5,525			5,272

The accompanying notes are an integral part of this statement.

F-4

Table of Contents

STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)



	Year Ended December 31,
	2016			2015			2014
Net loss	$	(590,586	)	$	(1,090,915	)	$	(189,543	)
Other comprehensive income (loss), net of tax effect:
Derivatives	(24,025		)	(62,758		)	88,178
Foreign currency translation	6,073			(2,605		)	(2,801		)
Comprehensive loss	$	(608,538	)	$	(1,156,278	)	$	(104,166	)

The accompanying notes are an integral part of this statement.

F-5

Table of Contents

STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)



	Year Ended December 31,
	2016			2015			2014
Cash flows from operating activities:
Net loss	$	(590,586	)	$	(1,090,915	)	$	(189,543	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	220,079			281,688			340,006
Write-down of oil and gas properties	357,431			1,362,447			351,192
Accretion expense	40,229			25,988			28,411
Deferred income tax provision (benefit)	13,080			(272,311		)	(102,177		)
Settlement of asset retirement obligations	(20,514		)	(72,382		)	(56,409		)
Non-cash stock compensation expense	8,443			12,324			11,325
Excess tax benefits	—			(1,586		)	—
Non-cash derivative expense (income)	1,471			16,440			(18,028		)
Non-cash interest expense	18,404			17,788			16,661
Non-cash reorganization items	8,332			—			—
Other non-cash expense	6,248			—			—
Change in current income taxes	20,088			(37,377		)	158
(Increase) decrease in accounts receivable	(1,412		)	43,724			51,611
(Increase) decrease in other current assets	(3,493		)	1,767			(6,244		)
Decrease in inventory	—			1,304			—
Increase (decrease) in accounts payable	1,026			(14,582		)	(3,419		)
Increase (decrease) in other current liabilities	9,897			(25,936		)	(19,152		)
Other	(10,135		)	(907		)	(3,251		)
Net cash provided by operating activities	78,588			247,474			401,141
Cash flows from investing activities:
Investment in oil and gas properties	(237,952		)	(522,047		)	(927,247		)
Proceeds from sale of oil and gas properties, net of expenses	—			22,839			242,914
Investment in fixed and other assets	(1,266		)	(1,549		)	(10,182		)
Change in restricted funds	1,046			179,467			(178,072		)
Net cash used in investing activities	(238,172		)	(321,290		)	(872,587		)
Cash flows from financing activities:
Proceeds from bank borrowings	477,000			5,000			—
Repayments of bank borrowings	(135,500		)	(5,000		)	—
Proceeds from building loan	—			11,770			—
Repayments of building loan	(423		)	—			—
Net proceeds from issuance of common stock	—			—			225,999
Deferred financing costs	(900		)	(68		)	(3,371		)
Excess tax benefits	—			1,586			—
Net payments for share-based compensation	(762		)	(3,127		)	(7,182		)
Net cash provided by financing activities	339,415			10,161			215,446
Effect of exchange rate changes on cash	(9		)	(74		)	(736		)
Net change in cash and cash equivalents	179,822			(63,729		)	(256,736		)
Cash and cash equivalents, beginning of year	10,759			74,488			331,224
Cash and cash equivalents, end of year	$	190,581		$	10,759		$	74,488
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	$	(32,130	)	$	(34,394	)	$	(14,076	)
Cash (paid) refunded for income taxes	25,762			7,212			(1		)

The accompanying notes are an integral part of this statement.

F-6

Table of Contents

STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)



	Common Stock		Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance, December 31, 2013	$	49	$	(860	)	$	1,398,324		$	(425,165	)	$	(2,062	)	$	970,286
Net loss	—		—			—			(189,543		)	—			(189,543		)
Adjustment for fair value accounting of derivatives, net of tax	—		—			—			—			88,178			88,178
Adjustment for foreign currency translation, net of tax	—		—			—			—			(2,801		)	(2,801		)
Exercise of stock options and vesting of restricted stock	—		—			(7,119		)	—			—			(7,119		)
Amortization of stock compensation expense	—		—			16,709			—			—			16,709
Net tax impact from stock option exercises and restricted stock vesting	—		—			(54		)	—			—			(54		)
Issuance of common stock	6		—			225,941			—			—			225,947
Balance, December 31, 2014	55		(860		)	1,633,801			(614,708		)	83,315			1,101,603
Net loss	—		—			—			(1,090,915		)	—			(1,090,915		)
Adjustment for fair value accounting of derivatives, net of tax	—		—			—			—			(62,758		)	(62,758		)
Adjustment for foreign currency translation, net of tax	—		—			—			—			(2,605		)	(2,605		)
Exercise of stock options and vesting of restricted stock	—		—			(2,638		)	—			—			(2,638		)
Amortization of stock compensation expense	—		—			17,524			—			—			17,524
Balance, December 31, 2015	55		(860		)	1,648,687			(1,705,623		)	17,952			(39,789		)
Net loss	—		—			—			(590,586		)	—			(590,586		)
Adjustment for fair value accounting of derivatives, net of tax	—		—			—			—			(24,025		)	(24,025		)
Adjustment for foreign currency translation, net of tax	—		—			—			—			6,073			6,073
Exercise of stock options, vesting of restricted stock and granting of stock awards	1		—			(732		)	—			—			(731		)
Amortization of stock compensation expense	—		—			11,776			—			—			11,776
Balance, December 31, 2016	$	56	$	(860	)	$	1,659,731		$	(2,296,209	)	$	—		$	(637,282	)

The accompanying notes are an integral part of this statement.

F-7

Table of Contents

STONE ENERGY CORPORATION

(Debtor-in-Possession)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In thousands of dollars, except per share and price amounts)

NOTE 1 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Operations

Stone Energy Corporation ("Stone" or the "Company") is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We began operating in the Gulf of Mexico (the "GOM") Basin in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. In connection with our restructuring efforts, we entered into a purchase and sale agreement to sell all of our Appalachia Properties (as defined in Note 2 – Chapter 11 Proceedings below). We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions, after which we will no longer have operations or assets in Appalachia. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia.

Voluntary Chapter 11 Filing

On December 14, 2016 (the "Petition Date"), the Company and its subsidiaries Stone Energy Offshore, L.L.C. ("Stone Offshore") and Stone Energy Holding, L.L.C. (together with the Company, the "Debtors") filed voluntary petitions (the "Bankruptcy Petitions") in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the "Bankruptcy Court") seeking relief under the provisions of Chapter 11 of Title 11 ("Chapter 11") of the United States Bankruptcy Code (the "Bankruptcy Code") to pursue a prepackaged plan of reorganization (the "Plan"). For additional details see Note 2 – Chapter 11 Proceedings. During the bankruptcy proceedings, the Debtors are operating as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court in accordance with applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. To assure ordinary course operations, the Debtors sought approval from the Bankruptcy Court for a variety of first day motions, including authority to maintain bank accounts and other customary relief. On February 15, 2017, the Bankruptcy Court entered an order (the "Confirmation Order") confirming the Plan, as modified by the Confirmation Order.

Summary of Significant Accounting Policies

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

Basis of Presentation:

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

On May 27, 2016, the board of directors of the Company approved a 1-for-10 reverse stock split of the Company's issued and outstanding shares of common stock. The reverse stock split was effective upon the filing and effectiveness of a certificate of amendment to the Company's certificate of incorporation after the market closed on June 10, 2016, and the common stock began trading on a split-adjusted basis when the market opened on June 13, 2016. The effect of the reverse stock split was to combine each 10 shares of outstanding common stock prior to the reverse split into one new share subsequent to the reverse split. The Company's authorized shares of common stock were proportionately decreased in connection with the reverse stock split. Additionally, the overall and per share limitations in the Company’s 2009 Amended and Restated Stock Incentive Plan, as amended from time to time, and outstanding awards thereunder were also proportionately adjusted. The Company retained the current par value of $.01 per share for all shares of common stock.

All references in the financial statements and notes thereto to number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the 1-for-10 reverse stock split. Stockholders' equity reflects the

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reverse stock split by reclassifying from common stock to additional paid-in capital an amount equal to the par value of the reduction in the number of shares as a result of the reverse split.

Reorganization:

We have applied Accounting Standards Codification ("ASC") 852, "Reorganizations", in preparing the consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees and other expenses incurred in the Chapter 11 cases, and unamortized deferred financing costs, premiums and discounts associated with debt classified as liabilities subject to compromise, have been recorded as reorganization items on the consolidated statement of operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the consolidated balance sheet at December 31, 2016 as liabilities subject to compromise. These liabilities are reported at the amounts the Company expects will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See Note 2 – Chapter 11 Proceedings for more information regarding reorganization items and liabilities subject to compromise.

The Chapter 11 proceedings do not include our former foreign subsidiary Stone Energy Canada, ULC. This subsidiary had no significant activity during 2016, except for the reclassification of approximately $6,081 of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the substantial liquidation of Stone Energy Canada, ULC. Stone Energy Canada, ULC was dissolved on December 2, 2016.

Use of Estimates:

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles ("GAAP") requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. 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, liabilities subject to compromise versus not subject to compromise, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative contracts, estimates of fair value in business combinations and contingencies.

Fair Value Measurements:

U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2016 and 2015, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.

Hybrid Debt Instruments:

In 2012, we issued $300,000 in aggregate principal amount of 1 3⁄4% Senior Convertible Notes due 2017 (the "2017 Convertible Notes"). See Note 11 – Debt. On that same day we entered into convertible note hedging transactions which were expected to reduce the potential dilution to our common shareholders upon conversion of the notes. In accordance with ASC 480-20 and ASC 470, we accounted for the debt and equity portions of the notes in a manner that reflects our nonconvertible borrowing rate when interest is recognized in subsequent periods. This results in the separation of the debt component, classification of the remaining component in stockholders’ equity, and accretion of the resulting discount as interest expense. Additionally, the hedging transactions met the criteria for classification as equity transactions and were recorded as such. The convertible note hedging transactions have since been terminated in connection with our Chapter 11 proceedings.

Cash and Cash Equivalents:

We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents.

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Oil and Gas Properties:

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

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

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

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

Asset Retirement Obligations:

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

Other Property and Equipment:

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

Earnings Per Common Share:

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

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Production Revenue:

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

Income Taxes:

Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment relative to successful wells are capitalized and recovered through DD&A, although for 2014, 2015 and 2016, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation.

Derivative Instruments and Hedging Activities:

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

Share-Based Compensation:

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

Recently Issued Accounting Standards:

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

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retrospective basis, which affected our disclosures of deferred tax assets and liabilities as of December 31, 2016 and 2015, but had no effect on our financial position, results of operations or cash flows.

NOTE 2 — CHAPTER 11 PROCEEDINGS:

Subject to certain exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Debtors or their property to recover, collect or secure a pre-petition claim. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements.

Restructuring Support Agreement

Prior to filing the Bankruptcy Petitions, on October 20, 2016, the Debtors entered into a restructuring support agreement (the "Original RSA") with certain holders of the Company’s 2017 Convertible Notes and the Company’s 7 1⁄2% Senior Notes due 2022 (the "2022 Notes") (collectively, the "Notes" and the holders thereof, the "Noteholders") to support a restructuring on the terms of the Plan. On November 17, 2016, the Debtors commenced a solicitation to seek acceptance by a majority of those voting in each voting class of claims of the Company’s creditors under the Plan, including (a) the lenders (the "Banks") under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the "Credit Facility") among Stone as borrower, Bank of America, N.A. as administrative agent and issuing bank, and the financial institutions named therein, and (b) the Noteholders. On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into an Amended and Restated Restructuring Support Agreement (the "A&R RSA") that amended, superseded and restated in its entirety the Original RSA. In connection with entry into the A&R RSA and the commencement of the bankruptcy cases, the Debtors amended the Plan. The solicitation period ended on December 16, 2016 and (i) of the 94.24% of Noteholders in aggregate outstanding principal amount that voted, 99.95% voted in favor of the Plan and .05% voted to reject the Plan, and (ii) 100% of the Banks voted to accept the Plan.

Upon emergence from bankruptcy by the Debtors, and pursuant to the terms of the Plan, as amended to be consistent with the terms of the A&R RSA and the term sheet annexed to the A&R RSA (the "Term Sheet") and as amended pursuant to the Settlement, Noteholders, Banks and other interest holders will receive treatment under the Plan, summarized as follows:


•	The Noteholders will receive their pro rata share of (a) $100,000 of cash, (b) 95% of the common stock in reorganized Stone and (c) $225,000 of new 7.5% second lien notes due 2022 (the "Second Lien Notes").

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•

Existing common stockholders of Stone will receive their pro rata share of 5% of the common stock in reorganized Stone and warrants for ownership of up to15% of reorganized Stone's common equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants. The warrants will have an exercise price equal to a total equity value of the reorganized Company that implies a 100% recovery of outstanding principal to the Company’s noteholders plus accrued interest through the Plan’s effective date less the face amount of the Second Lien Notes and the Prepetition Notes Cash (as defined in the Plan). The warrants may be exercised any time prior to the fourth anniversary of the Plan’s effective date, unless terminated earlier by their terms upon the consummation of certain business combinations or sale transactions involving the Company.

•

Banks signatory to the A&R RSA will receive their respective pro rata share of commitments and obligations under an amended credit agreement (the "Amended Credit Facility") on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25,000, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA, defined below.


•	All claims of creditors with unsecured claims other than claims by the Noteholders, including vendors, shall be unaltered and will be paid in full in the ordinary course of business to the extent such claims are undisputed.

Purchase and Sale Agreement

The A&R RSA contained certain covenants on the part of the Company and the Noteholders and Banks who are signatories to the A&R RSA, including that such Noteholders and Banks would support the sale of Stone's producing properties and acreage, including approximately 86,000 net acres, in the Appalachia regions of Pennsylvania and West Virginia (the "Appalachia Properties") to TH Exploration III, LLC, an affiliate of Tug Hill, Inc. ("Tug Hill"), pursuant to the terms of a Purchase and Sale Agreement dated October 20, 2016, as amended on December 9, 2016 (the "Tug Hill PSA"), and otherwise facilitate the restructuring transaction, in each case subject to certain terms and conditions in the A&R RSA. The consummation of the Plan is subject to customary conditions and other requirements, as well as the completion of the sale of the Appalachia Properties. Pursuant to the terms of the Tug Hill PSA, Stone agreed to sell the Appalachia Properties to Tug Hill for $360,000 in cash, subject to customary purchase price adjustments. In connection with the execution of the Tug Hill PSA, Tug Hill deposited $5,000 in escrow.

Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017, two additional bidders were allowed to participate in competitive bidding on the Appalachia Properties, and on January 18, 2017, the Bankruptcy Court approved certain bidding procedures (the "Bidding Procedures") in connection with the sale of the Appalachia Properties. In accordance with the Bidding Procedures, Stone conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT Corporation, through its wholly-owned subsidiary EQT Production Company ("EQT"), with a final purchase price of $527,000 in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court. See Note 21 – Subsequent Events. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors' may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to rejected contracts or leases may assert unsecured claims against the Debtors, as applicable, for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors, including where applicable a quantification of the Company's obligations under any such executory contact or unexpired lease of the Debtors, is qualified by any overriding rejection rights the Company has under the Bankruptcy Code.

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Potential Claims

The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing. Certain holders of pre-petition claims are required to file proofs of claim by the deadline for general claims (the "bar date"). Differences between amounts scheduled by the Debtors and claims by creditors will be investigated and resolved in connection with the claims resolution process. In light of the expected number of creditors, the claims resolution process may take considerable time to complete and will likely continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently ascertained.

Liabilities Subject to Compromise

We have applied ASC 852 in preparing our consolidated financial statements for periods subsequent to the filing of the Bankruptcy Petitions. The consolidated financial statements include amounts classified as "liabilities subject to compromise", which represent our current estimate of known or potential obligations to be resolved in connection with our Chapter 11 proceedings. Differences between liabilities we have estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts prospectively as necessary. Such adjustments may be material.

The following table summarizes the components of liabilities subject to compromise included in the Company's consolidated balance sheet as of December 31, 2016:



	December 31, 2016
1 3⁄4% Senior Convertible Notes due 2017	$	300,000
7 1⁄2% Senior Notes due 2022	775,000
Accrued interest payable	35,182
Liabilities subject to compromise	$	1,110,182

Reorganization Items

Under ASC 852, the direct and incremental costs resulting from the reorganization and restructuring of the business are reported separately as reorganization items on the statement of operations. The following table summarizes the components of reorganization items in the Company’s consolidated statement of operations for the year ended December 31, 2016:



	Twelve Months Ended December 31, 2016
Professional fees	$	2,615
Write-off of unamortized deferred financing costs	4,792
Write-off of unamortized discount and premium of Notes	3,540
Reorganization items	$	10,947

NOTE 3 — GOING CONCERN:

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.

The significant decline in commodity prices from mid-2014 through 2016 resulted in reduced revenue and cash flows and negatively impacted our liquidity position. Additionally, the level of our indebtedness and the depressed commodity price environment presented challenges related to our ability to comply with the covenants in the agreements governing our indebtedness. The minimum liquidity requirement and other restrictions under the Credit Facility also presented challenges with respect to our ability to meet interest payment obligations on the 2022 Notes as well as the maturity of the 2017 Convertible Notes. In order to address these issues, we worked with financial and legal advisors throughout 2016 and structured a plan of reorganization to

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address our liquidity and capital structure. In connection with our restructuring efforts, we entered into the Tug Hill PSA to sell all of our Appalachia Properties, and on December 14, 2016, the Debtors filed Bankruptcy Petitions seeking relief under the provisions of Chapter 11 of the Bankruptcy Code. Pursuant to Bankruptcy Court orders, we conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT. On February 9, 2017, we entered into the EQT PSA and on February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We expect to close on the sale of the Appalachia Properties by February 28, 2017. On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan. See Note 2 – Chapter 11 Proceedings. We expect the Plan to become effective on February 28, 2017, at which point we would emerge from bankruptcy. Upon emergence from bankruptcy, we expect that we will eliminate approximately $1,191,500 in principal amount of outstanding debt, resulting in remaining debt outstanding of approximately $236,284, consisting of $225,000 of Second Lien Notes and $11,284 outstanding under the Building Loan (see Note 11 – Debt).

While we expect the Plan to become effective on February 28, 2017, there can be no assurance that the effectiveness of the Plan will occur on such date, or at all. The uncertainty surrounding our Chapter 11 proceedings raises substantial doubt about our ability to continue as a going concern.

NOTE 4 — EARNINGS PER SHARE:

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):



	Year Ended December 31,
	2016			2015			2014
Income (numerator):
Basic:
Net loss	$	(590,586	)	$	(1,090,915	)	$	(189,543	)
Net income attributable to participating securities	—			—			—
Net loss attributable to common stock - basic	$	(590,586	)	$	(1,090,915	)	$	(189,543	)
Diluted:
Net loss	$	(590,586	)	$	(1,090,915	)	$	(189,543	)
Net income attributable to participating securities	—			—			—
Net loss attributable to common stock - diluted	$	(590,586	)	$	(1,090,915	)	$	(189,543	)
Weighted average shares (denominator):
Weighted average shares - basic	5,591			5,525			5,272
Dilutive effect of stock options	—			—			—
Weighted average shares - diluted	5,591			5,525			5,272
Basic loss per share	$	(105.63	)	$	(197.45	)	$	(35.95	)
Diluted loss per share	$	(105.63	)	$	(197.45	)	$	(35.95	)

All outstanding stock options were considered antidilutive during the years ended December 31, 2016 (12,900 shares), December 31, 2015 (14,400 shares) and December 31, 2014 (20,500 shares) because we had net losses for such years.

During the years ended December 31, 2016, 2015 and 2014, approximately 79,621, 41,375 and 38,034 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock, the granting of stock awards and the exercise of stock options by employees and nonemployee directors. In May 2014, 575,000 shares of our common stock were issued in a public offering.

For the years ended December 31, 2016, 2015 and 2014, the 2017 Convertible Notes had no dilutive effect on the diluted earnings per share computation as we had net losses for such years. For the years ended December 31, 2016, 2015 and 2014, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 11 – Debt) and therefore, such warrants were not dilutive for such years. Based on the terms of the Purchased Call Options (as defined in Note 11 – Debt), such call options are antidilutive and therefore were not included in the calculation of diluted earnings per share.

On February 15, 2017, our Plan was confirmed by the Bankruptcy Court. The Plan provides, as discussed in Note 2 – Chapter 11 Proceedings, that the Company's currently authorized common stock will be cancelled as of the consummation date of the Bankruptcy Proceedings. On such date, existing holders of common stock in Stone will receive their pro rata share of 5% of the

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common stock in reorganized Stone and warrants for ownership of up to 15% of reorganized Stone's common equity, exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants.

NOTE 5 — ACCOUNTS RECEIVABLE:

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



	As of December 31,
	2016		2015
Other co-venturers	$	3,532	$	4,639
Trade	42,944		26,224
Unbilled accounts receivable	591		1,736
Other	1,397		15,432
Total accounts receivable	$	48,464	$	48,031

NOTE 6 — CONCENTRATIONS:

Sales to Major Customers

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



	Year Ended December 31,
	2016		2015		2014
Phillips 66 Company	68	%	53	%	31	%
Shell Trading (US) Company	10	%	13	%	32	%

The maximum amount of credit risk exposure at December 31, 2016 relating to these customers was $27,736.

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

Production and Reserve Volumes – Unaudited

Approximately 66% of our estimated proved reserve volumes at December 31, 2016 and 65% of our production during 2016 were associated with our GOM deep water, conventional shelf and deep gas properties. Approximately 34% of our estimated proved reserve volumes at December 31, 2016 and 35% of our production during 2016 were associated with the Appalachia Properties.

Cash and Cash Equivalents

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

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. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.

During 2016, 2015 and 2014, a portion of our oil and natural gas production was hedged with fixed-price swaps and collars with various counterparties. We did not have any outstanding derivative contracts at December 31, 2016. In January and February 2017, we entered into various fixed-price swaps and put contracts for a portion of our expected 2017 and 2018 oil production from

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the Gulf Coast Basin. As of February 23, 2017, our outstanding fixed-price swaps and put contracts are with Natixis, Bank of America Merrill Lynch, The Toronto-Dominion Bank and The Bank of Nova Scotia.

Our fixed-price oil swap settlements are based on an average of the New York Mercantile Exchange ("NYMEX") closing price for West Texas Intermediate ("WTI") crude oil during the entire calendar month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. 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 NYMEX prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above the floor. Our put contract settlements are based on the average of the NYMEX closing price for WTI crude oil during the entire calendar month.

The following tables illustrate our derivative positions for calendar years 2017 and 2018 as of February 23, 2017:



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



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

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 February 23, 2017, our derivative instruments were with four counterparties, one of which hedged approximately 37% of our total contracted volumes and three of which each hedged approximately 21% of our total contracted volumes. All of our outstanding derivative instruments are with lenders under our current bank credit facility.

We previously discontinued hedge accounting for certain 2015 natural gas contracts, as it became no longer probable, subsequent to the sale of our non-core GOM conventional shelf properties, that our GOM natural gas production would be sufficient to cover the GOM volumes hedged. Additionally, a small portion of our cash flow hedges are typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products are not 100% correlative to changes in the underlying price basis indicative in the derivative contract.

Derivatives qualifying as hedging instruments:

We had no outstanding hedging instruments at December 31, 2016. The following table discloses the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2015.

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Fair Value of Derivatives Qualifying as Hedging Instruments at
December 31, 2015
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	38,576	Current liabilities: Fair value of derivative contracts	$	—
	Long-term assets: Fair value of derivative contracts	—		Long-term liabilities: Fair value of derivative contracts	—
		$	38,576		$	—

The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the years ended December 31, 2016, 2015 and 2014:



Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Years Ended December 31, 2016, 2015, and 2014
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives			Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)			Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
				Location			Location
	2016				2016			2016
Commodity contracts	$	(1,648	)	Operating revenue - oil/natural gas production	$	35,457	Derivative income (expense), net	$	(810	)
Total	$	(1,648	)		$	35,457		$	(810	)

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

	2014				2014			2014
Commodity contracts	$	136,097		Operating revenue - oil/natural gas production	$	526	Derivative income (expense), net	$	5,721
Total	$	136,097			$	526		$	5,721

(a)

For the year ended December 31, 2016, effective hedging contracts increased oil revenue by $23,747 and increased natural gas revenue by $11,710. For the year ended December 31, 2015, effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338. For the year ended December 31, 2014, effective hedging contracts increased oil revenue by $7,929 and decreased natural gas revenue by $7,403.

Derivatives not qualifying as hedging instruments:

Gains or losses related to changes in fair value and cash settlements for derivatives not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations for the years ended December 31, 2016, 2015 and 2014.



Gain (Loss) Recognized in Derivative Income (Expense)
	Year Ended
Description	December 31, 2016		December 31, 2015			December 31, 2014
Commodity contracts:
Cash settlements	$	—	$	17,385		$	1,484
Change in fair value	—		(12,146		)	12,146
Total gain on non-qualifying derivatives	$	—	$	5,239		$	13,630

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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. We had no outstanding derivative contracts as of December 31, 2016. As of December 31, 2015, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

NOTE 8 — FAIR VALUE MEASUREMENTS:

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

As of December 31, 2016 and 2015, 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. We used the income approach in determining the fair value of our derivative instruments utilizing a 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.

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



	Fair Value Measurements at
	December 31, 2016
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	8,746	$	8,746	$	—	$	—
Total	$	8,746	$	8,746	$	—	$	—



	Fair Value Measurements at
	December 31, 2015
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	8,499	$	8,499	$	—	$	—
Derivative contracts	38,576		—		36,603		1,973
Total	$	47,075	$	8,499	$	36,603	$	1,973

The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the year ended December 31, 2016.

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	Hedging Contracts, net
Balance as of January 1, 2016	$	1,973
Total gains/(losses) (realized or unrealized):
Included in earnings	1,111
Included in other comprehensive income	(1,910		)
Purchases, sales, issuances and settlements	(1,174		)
Transfers in and out of Level 3	—
Balance as of December 31, 2016	$	—
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at December 31, 2016	$	—

The fair value of cash and cash equivalents approximated book value at December 31, 2016 and 2015. As of December 31, 2016 and 2015, the fair value of the liability component of the 2017 Convertible Notes was approximately $293,530 and $217,117, respectively. As of December 31, 2016 and 2015, the fair value of the 2022 Notes was approximately $465,000 and $271,250, respectively.

The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see Note 11 – Debt) at inception and at December 31, 2016 and 2015. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

NOTE 9 — ASSET RETIREMENT OBLIGATIONS:

The change in our asset retirement obligations during the years ended December 31, 2016, 2015 and 2014 is set forth below:



	Year Ended December 31,
	2016			2015			2014
Asset retirement obligations as of the beginning of the year, including current portion	$	225,866		$	316,409		$	502,513
Liabilities incurred	2,338			15,933			28,606
Liabilities settled	(19,630		)	(72,713		)	(55,839		)
Divestment of properties	—			(248		)	(137,801		)
Accretion expense	40,229			25,988			28,411
Revision of estimates	(6,784		)	(59,503		)	(49,481		)
Asset retirement obligations as of the end of the year, including current portion	$	242,019		$	225,866		$	316,409

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NOTE 10 — INCOME TAXES:

An analysis of our deferred taxes follows:



	As of December 31,
	2016			2015
Tax effect of temporary differences:
Net operating loss carryforwards	$	201,557		$	31,624
Oil and gas properties	85,772			76,766
Asset retirement obligations	85,312			79,618
Stock compensation	3,294			5,199
Hedges	—			(13,598		)
Accrued incentive compensation	954			1,234
Debt issuance costs	7,480			—
Other	441			(722		)
Total deferred tax assets (liabilities)	384,810			180,121
Valuation allowance	(384,810		)	(180,121		)
Net deferred tax assets (liabilities)	$	—		$	—

We estimate that we had ($5,674), ($44,096) and $159 of current federal income tax expense (benefit) for the years ended December 31, 2016, 2015 and 2014, respectively. For the years ended December 31, 2016, 2015 and 2014, we recorded deferred income tax expense (benefits) of $13,080, ($272,311) and ($102,177), respectively. The deferred income tax benefits were a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (see Note 17 – Supplemental Information on Oil and Natural Gas Operations – Unaudited). We had current income tax receivables of $26,086 and $46,174 at December 31, 2016 and 2015, respectively, both of which related to expected tax refunds from the carryback of net operating losses to previous tax years.

For tax reporting purposes, net operating loss carryforwards totaled approximately $599,144 at December 31, 2016. If not utilized, the majority of such carryforwards would expire in 2035 and would fully expire in 2036. In addition, we had approximately $1,050 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these and other carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets. As of December 31, 2016, our valuation allowance totaled $384,810. 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.

A reconciliation between the statutory federal income tax rate and our effective income tax rate as a percentage of income before income taxes follows:



	Year Ended December 31,
	2016	2015	2014
Income tax expense computed at the statutory federal income tax rate	35.0%	35.0%	35.0%
State taxes	0.2	0.6	1.0
Change in valuation allowance	(35.0)	(12.8)	—
IRC Sec. 162(m) limitation	(0.3)	(0.1)	(0.5)
Tax deficits on stock compensation	(0.7)	(0.1)	(0.2)
Reorganization fees	(0.3)	—	—
Other	(0.2)	(0.1)	(0.3)
Effective income tax rate	(1.3)%	22.5%	35.0%

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Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to ($13,080), ($35,737) and $49,601 for the years ended December 31, 2016, 2015 and 2014, respectively.

As of December 31, 2016, we had unrecognized tax benefits of $491. If recognized, all of our unrecognized tax benefits would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows:



Total unrecognized tax benefits as of December 31, 2015	$	491
Increases (decreases) in unrecognized tax benefits as a result of:
Tax positions taken during a prior period	—
Tax positions taken during the current period	—
Settlements with taxing authorities	—
Lapse of applicable statute of limitations	—
Total unrecognized tax benefits as of December 31, 2016	$	491

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

It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. We recognized $46 of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2016. We recognized $131 of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2015. No such amounts were recognized for the year ended December 31, 2014. The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet.

The tax years 2013 through 2016 remain subject to examination by major tax jurisdictions.

NOTE 11 — DEBT:

Our debt consisted of the following at:



	December 31,
	2016			2015
1 3⁄4% Senior Convertible Notes due 2017	$	300,000		$	279,244
7 1⁄2% Senior Notes due 2022	775,000			770,009
Revolving credit facility	341,500			—
4.20% Building Loan	11,284			11,702
Total debt	$	1,427,784		$	1,060,955
Less: current portion of long-term debt	(408		)	—
Less: liabilities subject to compromise (see Note 2)	(1,075,000		)	—
Long-term debt	$	352,376		$	1,060,955

Bankruptcy Filing

On December 14, 2016, the Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code. The Bankruptcy Petitions constituted an event of default that accelerated the Company's obligations under all of its outstanding debt instruments, resulting in the principal and interest due thereunder immediately due and payable. However, any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Bankruptcy Petitions, and the creditors' rights of enforcement in respect of the debt instruments were subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. On February 15, 2017, the Bankruptcy Court confirmed the Plan. See Note 2 – Chapter 11 Proceedings for additional information on the Bankruptcy Proceedings.

Current Portion of Long-Term Debt

As of December 31, 2016, the current portion of long-term debt of $408 represented principal payments due within one year on the 4.20% Building Loan (the "Building Loan").

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Reclassification of Debt

The face value of the 2017 Convertible Notes of $300,000 and the 2022 Notes of $775,000 have been reclassified as liabilities subject to compromise in the accompanying consolidated balance sheet at December 31, 2016. Additionally, we recognized a charge of approximately $8,332 to write-off the remaining unamortized deferred financing costs, discounts and premiums related to the 2017 Convertible Notes and 2022 Notes and a charge of $2,615 for costs directly related to the bankruptcy proceedings, including legal and financial advisory costs for Stone, our bank group and our noteholders incurred post-bankruptcy filing, which are included in reorganization items in the accompanying consolidated statement of operations for the year ended December 31, 2016. See Note 1 – Organization and Summary of Significant Accounting Policies.

Revolving Credit Facility

On June 24, 2014, we entered into the Credit Facility with commitments totaling $900,000 (subject to borrowing base limitations) through a syndicated bank group, with an initial borrowing base of $500,000. The Credit Facility matures on July 1, 2019. On April 13, 2016, our borrowing base under the Credit Facility was reduced from $500,000 to $300,000. On that date, we had $457,000 of outstanding borrowings and $18,269 of outstanding letters of credit, or $175,269 in excess of the redetermined borrowing base (referred to as a borrowing base deficiency). Our agreement with the banks provides that within 30 days after notification of a borrowing base deficiency, we must elect to cure the borrowing base deficiency through any combination of the following actions: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments. We elected to pay the deficiency in six equal monthly installments, making the first payment of $29,212 on May 13, 2016 and the second payment of $29,212 on June 13, 2016.

On June 14, 2016, we entered into Amendment No. 3 (the "June Amendment") to the Credit Facility to (i) increase the borrowing base to $360,000 from $300,000, (ii) provide for no redetermination of the borrowing base by the lenders until January 15, 2017, other than an automatic reduction upon the sale of certain of our properties, (iii) permit second lien indebtedness to refinance the existing 2017 Convertible Notes and 2022 Notes, (iv) revise the maximum Consolidated Funded Leverage financial covenant to be 5.25 to 1 for the fiscal quarter ended June 30, 2016, 6.50 to 1 for the fiscal quarter ended September 30, 2016, 9.50 to 1 for the fiscal quarter ended December 31, 2016 and 3.75 to 1 thereafter, (v) require minimum liquidity (as defined in the June Amendment) of at least $125,000 until January 15, 2017, (vi) impose limitations on capital expenditures of $60,000 for the period of June 1, 2016 through December 31, 2016, but allowing for an additional $25,000 to be expended for Appalachian drilled but uncompleted wells, (vii) grant the lenders a perfected security interest in all deposit accounts and (viii) provide for anti-hoarding cash provisions for amounts in excess of $50,000 to apply after December 10, 2016. Upon execution of the June Amendment, we repaid $56,845 in borrowings under the Credit Facility, which eliminated the borrowing base deficiency and brought the total borrowings and letters of credit outstanding under the Credit Facility in conformity with the borrowing base limitation.

As of December 31, 2016 and February 23, 2017, we had $341,500 of outstanding borrowings and $12,469 of outstanding letters of credit, leaving $6,031 of availability under the Credit Facility. The weighted average interest rate under the Credit Facility was approximately 3.2% at December 31, 2016. Subject to certain exceptions, the Credit Facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of December 31, 2016, the Credit Facility was guaranteed by our only material subsidiary, Stone Offshore. On August 29, 2016, our subsidiaries SEO A LLC and SEO B LLC were merged into Stone Offshore.

The borrowing base under the Credit Facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the Credit Facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. The Credit Facility is collateralized by substantially all of our assets and the assets of our material subsidiaries. We are required to mortgage, and grant a security interest in, our oil and natural gas reserves representing at least 86% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Interest on loans under the Credit Facility is calculated using the London Interbank Offering ("LIBOR") rate or the base rate, at our election. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%.

In addition to the covenants discussed above, the Credit Facility provides that we must maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the Credit Facility, for the preceding four quarterly periods of not less than 2.5 to 1. As of December 31, 2016, our Consolidated Funded Debt to consolidated EBITDA ratio was 6.90 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 3.24 to 1. The Credit Facility also includes

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certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of December 31, 2016, however, the Bankruptcy Petitions constituted an event of default that accelerated the Company's obligations under the Credit Facility, resulting in the principal and interest due thereunder immediately due and payable. Any efforts to enforce such payment obligations were automatically stayed as a result of the filing of the Bankruptcy Petitions, and the lenders' rights of enforcement in respect of such amounts were subject to the applicable provisions of the Bankruptcy Code.

On December 14, 2016, the Debtors and the Banks holding 100% of the aggregate principal amount owing under the Credit Facility entered into the A&R RSA, pursuant to which the Banks will receive their respective pro rata share of commitments and obligations under the Amended Credit Facility on the terms set forth in Exhibit 1(a) to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25,000, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA. The terms of the Amended Credit Facility under the Plan are substantially consistent with the pre-petition facility, except, the borrowing base will be reduced to $200,000, subject to a $150,000 borrowing cap until the first redetermination of the borrowing base scheduled for November 1, 2017, and subject to decrease under certain circumstances. Additionally, the Consolidated Funded Leverage financial covenant will be adjusted to levels ranging from 2.50 to 1 to 3.00 to 1 for 2017 and ranging from 2.50 to 1 to 3.50 to 1 thereafter. The margin for loans at the LIBOR rate will be increased to a range of 3.00% to 4.00%.

Building Loan

On November 20, 2015, we entered into an $11,802 term loan agreement, the Building Loan, maturing on December 20, 2030. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of $73 commencing on December 20, 2015. The Building Loan is collaterized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. As of December 31, 2016, our EBITDA to Net Interest Expense ratio was 3.24 to 1. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. There will be no changes to the terms of the Building Loan pursuant to the Plan.

2017 Convertible Notes

On March 6, 2012, we issued in a private offering $300,000 in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the "Securities Act"). The 2017 Convertible Notes are convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, based on an initial conversion rate of 23.4449 shares of our common stock per $1 principal amount of 2017 Convertible Notes, which corresponded to an initial conversion price of approximately $42.65 per share of our common stock at the time of the issuance of the 2017 Convertible Notes. The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture related to the 2017 Convertible Notes. On June 10, 2016, we completed a 1-for-10 reverse stock split with respect to our common stock (see Note 1 – Organization and Summary of Significant Accounting Policies). Proportional adjustments were made to the conversion price and shares as they relate to the 2017 Convertible Notes, resulting in a conversion rate of 2.34449 shares of our common stock with a corresponding conversion price of $426.50 per share. On December 31, 2016, our closing share price was $7.15.

The 2017 Convertible Notes may be converted by the holder, in multiples of $1 principal amount, under certain circumstances, including on or after December 1, 2016, and prior to the close of business on the second scheduled trading day immediately preceding the maturity date of the 2017 Convertible Notes, which is March 1, 2017, without regard to the conditions specified in the indenture governing the 2017 Convertible Notes.

Upon conversion, we will be obligated to pay or deliver, as the case may be, cash, shares of our common stock or a combination of cash and shares of our common stock. If we satisfy our conversion obligation solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of our common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture related to the 2017 Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture related to the 2017 Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 2017 Convertible Notes will not receive any cash payment representing accrued and unpaid interest. Instead, interest will be deemed to be paid by the cash, shares of our common stock or a combination of cash and shares of our common stock paid or delivered, as the case may be, upon conversion of a 2017 Convertible Note.

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

In connection with the offering, we entered into convertible note hedge transactions with respect to our common stock (the "Purchased Call Options") with Barclays Capital Inc., acting as agent for Barclays Bank PLC and Bank of America, N.A. (the "Dealers"). We paid an aggregate amount of approximately $70,830 to the Dealers for the Purchased Call Options. The Purchased Call Options cover, subject to customary antidilution adjustments, approximately 703,347 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes (after the effectiveness of the reverse stock split of 1-for-10), also subject to adjustment, and are exercisable upon conversion of the 2017 Convertible Notes.

We also entered into separate warrant transactions whereby, in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately 703,347 shares of our common stock (the "Sold Warrants") at a strike price of $559.10 per share of our common stock (after the effectiveness of the reverse stock split of 1-for-10). We received aggregate proceeds of approximately $40,170 from the sale of the Sold Warrants to the Dealers. If, upon expiration of the Sold Warrants, the price per share of our common stock, as measured under the Sold Warrants, is greater than the strike price of the Sold Warrants, we will be required to issue, without further consideration, under each Sold Warrant a number of shares of our common stock with a value equal to the amount of such difference.

The filing of the Bankruptcy Petitions resulted in an event of default and the early termination of the convertible note hedge transactions. Any efforts to enforce payment obligations under the indenture governing the 2017 Convertible Notes were automatically stayed as a result of the Chapter 11 filings.

As of December 31, 2016, the principal amount of the 2017 Convertible Notes of $300,000 was classified as liabilities subject to compromise. During the year ended December 31, 2016, we recognized $15,407 of interest expense for the amortization of the discount and $1,471 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2015, we recognized $15,019 of interest expense for the amortization of the discount and $1,434 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2014, we recognized $13,951 of interest expense for the amortization of the discount and $1,332 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2016, we recognized $5,010 of interest expense and during each of the years ended December 31, 2015 and 2014, we recognized $5,250 of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

2022 Notes

On November 8, 2012, we completed the public offering of $300,000 aggregate principal amount of our 2022 Notes, which are fully and unconditionally guaranteed on a senior unsecured basis by Stone Offshore and by certain future restricted subsidiaries of Stone. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $293,203. On November 27, 2013, we completed the public offering of an additional $475,000 aggregate principal amount of our 2022 Notes at a 3% premium. The net proceeds from this offering after deducting underwriting discounts, commissions, fees and expenses totaled $480,195. The 2022 Notes rank equally in right of payment with all of our existing and future senior debt, and rank senior in right of payment to all of our existing and future subordinated debt. The 2022 Notes mature on November 15, 2022, and interest is payable on the 2022 Notes on each May 15 and November 15. We may redeem some or all of the 2022 Notes at any time on or after November 15, 2017 at the redemption prices specified in the indenture, and we may redeem some or all of the 2022 Notes prior to November 15, 2017 at a make-whole redemption price as specified in the indenture. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness, or we experience certain changes of control, each as described in the indenture, we must offer to repurchase the 2022 Notes. The 2022 Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. The violation of any of these covenants could give rise to a default, which if not cured could give the holder of the 2022 Notes a right to accelerate payment.

We had an interest payment obligation under our 2022 Notes of approximately $29,063, due on November 15, 2016. The indenture governing the 2022 Notes provides a 30-day grace period that extended the latest date for making this cash interest payment to December 15, 2016 before an event of default occurs under the indenture, which would give the trustee or the holders of at least 25% in principal amount of the 2022 Notes the option to accelerate payment of the principal plus accrued and unpaid interest on the 2022 Notes. Although we had sufficient liquidity to make the interest payment by the due date, we elected to not make this interest payment on the due date and utilized the 30-day grace period provided by the indenture prior to entering into the Chapter 11 proceedings. The filing of the Bankruptcy Petitions constituted an event of default under the indenture governing

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the 2022 Notes, but any efforts to enforce such payment obligation were automatically stayed as a result of the Chapter 11 filings. The principal amount of $775,000 of the 2022 Notes was classified as liabilities subject to compromise at December 31, 2016.

Deferred Financing Cost and Interest Cost

We recognized a charge to write-off the remaining unamortized deferred financing costs, premiums and discounts related to the 2017 Convertible Notes and the 2022 Notes as of the Petition Date, which is included in reorganization items on the consolidated statement of operations. See Note 1 – Organization and Summary of Significant Accounting Policies. At December 31, 2016, approximately $63 of unamortized deferred financing costs were deducted from the carrying amount of the Building Loan. At December 31, 2015, approximately $6,869 of unamortized deferred financing costs, premiums and discounts were included within the carrying amount of the related debt liabilities for the 2017 Convertible Notes, 2022 Notes and Building Loan. The deferred financing costs, net of accumulated amortization, of $2,761 and $2,845 at December 31, 2016 and 2015, respectively, related to the Credit Facility are classified as other assets.

Prior to the filing of the Bankruptcy Petitions, the costs associated with the 2017 Convertible Notes were being amortized over the life of the notes using a method that applied an effective interest rate of 7.51%. The costs associated with the November 2012 issuance and November 2013 issuance of the 2022 Notes were being amortized over the life of the notes using a method that applied effective interest rates of 7.75% and 7.04%, respectively.

The costs associated with the issuance of the Building Loan are being amortized using the effective interest method over the term of the Building Loan. The costs associated with the Credit Facility are being amortized on a straight-line basis over the term of the facility.

Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2016, 2015 and 2014 was $91,092, $85,267 and $84,577, respectively. In accordance with the accounting guidance in ASC 852, we have accrued interest on the Notes only up to the Petition Date, and such amounts are included as liabilities subject to compromise in our consolidated balance sheet at December 31, 2016. Accordingly, there was no interest expense recognized on the 2017 Convertible Notes or the 2022 Notes after the Bankruptcy Petitions were filed.

NOTE 12 — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):

The following tables include the changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2016, 2015 and 2014. During the year ended December 31, 2016, we reclassified approximately $6,081 of losses related to cumulative foreign currency translation adjustments from accumulated other comprehensive income into other operational expenses upon the liquidation of our former foreign subsidiary, Stone Energy Canada, ULC. See Note 1 - Organization and Summary of Significant Accounting Policies.



	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2016
Beginning balance, net of tax	$	24,025		$	(6,073	)	$	17,952
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	(1,648		)	—			(1,648		)
Foreign currency translations	—			(8		)	(8		)
Income tax effect	581			—			581
Net of tax	(1,067		)	(8		)	(1,075		)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	35,457			—			35,457
Other operational expenses	—			(6,081		)	(6,081		)
Income tax effect	(12,499		)	—			(12,499		)
Net of tax	22,958			(6,081		)	16,877
Other comprehensive income (loss), net of tax	(24,025		)	6,073			(17,952		)
Ending balance, net of tax	$	—		$	—		$	—

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	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2015
Beginning balance, net of tax	$	86,783		$	(3,468	)	$	83,315
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	52,630			—			52,630
Foreign currency translations	—			(2,605		)	(2,605		)
Income tax effect	(19,096		)	—			(19,096		)
Net of tax	33,534			(2,605		)	30,929
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	149,955			—			149,955
Derivative income, net	1,170			—			1,170
Income tax effect	(54,833		)	—			(54,833		)
Net of tax	96,292			—			96,292
Other comprehensive loss, net of tax	(62,758		)	(2,605		)	(65,363		)
Ending balance, net of tax	$	24,025		$	(6,073	)	$	17,952



	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2014
Beginning balance, net of tax	$	(1,395	)	$	(667	)	$	(2,062	)
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	136,097			—			136,097
Foreign currency translations	—			(2,801		)	(2,801		)
Income tax effect	(48,995		)	—			(48,995		)
Net of tax	87,102			(2,801		)	84,301
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	526			—			526
Derivative expense, net	(2,208		)	—			(2,208		)
Income tax effect	606			—			606
Net of tax	(1,076		)	—			(1,076		)
Other comprehensive income (loss), net of tax	88,178			(2,801		)	85,377
Ending balance, net of tax	$	86,783		$	(3,468	)	$	83,315

NOTE 13 — SHARE-BASED COMPENSATION:

Prior to December 17, 2015, we maintained the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, as amended from time to time (the "2009 Plan"). The 2009 Plan was originally approved at the 2009 Annual Meeting of Stockholders and was an amendment and restatement of the Company’s 2004 Amended and Restated Stock Incentive Plan (the "2004 Plan"), and it superseded and replaced in its entirety the 2004 Plan. The 2009 Plan provides for the granting of (a) "incentive" stock options as defined in Section 422 of the Code, (b) stock options that do not constitute incentive stock options ("non-statutory" stock options), (c) stock appreciation rights in conjunction with an incentive or non-statutory stock option, (d) restricted stock, (e) restricted stock units, (f) dividend equivalents, (g) other stock-based awards, (h) conversion awards, and (i) cash awards, any of which may be further designated as performance awards (collectively referred to as "awards"). On December 17, 2015, Stone amended and restated the 2009 Plan to incorporate all prior amendments to the 2009 Plan and certain other non-material changes to the 2009 Plan. See Note 16 – Employee Benefit Plans – Stock Incentive Plans for more information.

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No stock options have been granted pursuant to the 2009 Plan since its initial effective date on May 28, 2009; however, we have previously granted options under the 2004 Plan that remain outstanding. Stock options previously granted to employees vested ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock options issued to nonemployee directors vested ratably over a three-year service-vesting period and expire 10 years subsequent to award. We have granted restricted stock awards under the 2009 Plan, which awards typically vest over a one-year or three-year period.

We record share-based compensation expense for share-based compensation awards based on the fair value on the date of grant. Compensation expense for share-based compensation awards is recognized in our financial statements on a straight-line basis over the vesting period of the award.

For the year ended December 31, 2016, we incurred $11,562 of share-based compensation related to restricted stock issuances or granting of stock awards, and of which a total of approximately $3,117 was capitalized into oil and gas properties. For the year ended December 31, 2015, we incurred $17,917 of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5,593 was capitalized into oil and gas properties. For the year ended December 31, 2014, we incurred $17,051 of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5,797 was capitalized into oil and gas properties. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash provided by operating activities in our statement of cash flows. The capitalized portion is not included in net cash used in investing activities.

The Plan, as described in Note 2 – Chapter 11 Proceedings, provides that the Company's common stock will be cancelled and new common stock will be issued upon emergence from bankruptcy. On February 15, 2017, the Plan was confirmed by the Bankruptcy Court and we expect to emerge from bankruptcy on February 28, 2017. Immediately prior to emergence, the vesting of all outstanding, unvested share-based awards for non-executive employees will be accelerated. Upon emergence from bankruptcy, all outstanding, unvested restricted shares held by the Company’s executives will be cancelled and exchanged for a proportionate share of 5% of the common stock of reorganized Stone, plus warrants for ownership of up to 15% of reorganized Stone’s common equity. Vesting will continue in accordance with the applicable vesting provisions of the original awards. All other executive share-based awards will be cancelled upon emergence from bankruptcy.

Stock Options. There were no stock option grants during the years ended December 31, 2016, 2015 or 2014. The following tables include stock option activity during the years ended December 31, 2016, 2015 and 2014 (amounts in tables represent actual values except where indicated otherwise).



	Year Ended December 31, 2016
	Number of Options		Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	14,447		$	269.25
Granted	—		—
Exercised	—		—
Forfeited	—		—
Expired	(1,500	)	477.45
Options outstanding, end of period (1)	12,947		245.13		1.4 years	$	—
Options exercisable, end of period	12,947		245.13		1.4 years	—
Options unvested, end of period	—		—		—	—

(1) Exercise prices for stock options outstanding at December 31, 2016 range from $69.70 to $446.70.

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	Year Ended December 31, 2015
	Number of Options		Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	20,497		$	339.36
Granted	—		—
Exercised	—		—
Forfeited	—		—
Expired	(6,050	)	506.76
Options outstanding, end of period	14,447		269.25		2.1 years	$	—
Options exercisable, end of period	14,447		269.25		2.1 years	—
Options unvested, end of period	—		—		—	—



	Year Ended December 31, 2014
	Number of Options		Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	33,117		$	393.74
Granted	—		—
Exercised	(25	)	462.00
Forfeited	—		—
Expired	(12,595	)	482.11
Options outstanding, end of period	20,497		339.36		2.4 years	$	531
Options exercisable, end of period	20,497		339.36		2.4 years	531
Options unvested, end of period	—		—		—	—

Restricted Stock and Other Stock Awards. The fair value of restricted shares and stock awards is typically determined based on the average of our high and low stock prices on the grant date. During the year ended December 31, 2016, we issued 31,313 shares of restricted stock or stock awards valued at $280. During the year ended December 31, 2015, we issued 141,872 shares of restricted stock valued at $23,722. During the year ended December 31, 2014, we issued 67,305 shares of restricted stock valued at $24,593.

A summary of the restricted stock and stock award activity under the 2009 Plan for the years ended December 31, 2016, 2015 and 2014 is as follows (amounts in table represent actual values):



	2016				2015				2014
	Number of Restricted Shares		Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares		Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares		Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding, beginning of period	180,239		$	208.17	129,848		$	299.45	125,334		$	239.07
Issuances	31,313		8.93		141,872		167.21		67,305		365.40
Lapse of restrictions or granting of stock awards	(117,406	)	158.79		(63,745	)	296.00		(59,731	)	245.73
Forfeitures	(13,056	)	200.06		(27,736	)	223.80		(3,060	)	301.54
Restricted stock outstanding, end of period	81,090		$	205.34	180,239		$	208.17	129,848		$	299.45

As of December 31, 2016, there was $2,823 of unrecognized compensation cost related to unvested share-based awards for non-executive employees and $3,318 of unrecognized compensation cost related to unvested restricted shares held by the Company's executives. The current weighted average remaining vesting period of such awards is approximately one year.

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Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital and/or an increase in income tax expense, depending on the pool of available excess tax benefits to offset such deficit. There were no adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting in 2016 or 2015 and such adjustments were ($54) in 2014. Additionally, during 2016, 2015, and 2014, $4,117, $1,314 and $609 of tax deficits were charged to income tax expense, respectively.

NOTE 14 — SHARE REPURCHASE PROGRAM:

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100,000. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Through December 31, 2016, 30,000 shares had been repurchased under this program at a total cost of $7,071, or an average price of $235.70 per share (after the effectiveness of the reverse stock split of 1-for-10). No shares were repurchased during the years ended December 31, 2016, 2015 and 2014.

NOTE 15 — COMMITMENTS AND CONTINGENCIES:

Chapter 11 Proceedings

The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect pre-petition liabilities or to exercise control over the property of the Debtors. The Plan in our Chapter 11 proceedings provides for the treatment of pre-petition liabilities that have not otherwise been satisfied or addressed during the Chapter 11 cases. See Note 2 – Chapter 11 Proceedings.

Legal Proceedings

Leases

We lease office facilities in Lafayette and New Orleans, Louisiana, Houston, Texas and New Martinsville and Morgantown, West Virginia under the terms of long-term, non-cancelable leases expiring on various dates through 2021. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net annual commitments under all leases, subleases and contracts with non-cancelable terms in excess of 12 months at December 31, 2016 were as follows:



2017	$	877
2018	612
2019	453
2020	453
2021	113

Payments related to our lease obligations for the years ended December 31, 2016, 2015 and 2014 were approximately $676, $2,076 and $966, respectively.

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. BOEM's notice letters indicated the amount of Stone's supplemental bonding needs could be as much as $565,000. In late March 2016, we proposed a tailored plan to BOEM for financial assurances relating to our abandonment obligations, which provides for posting some incremental financial assurances in favor of BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the understanding that we will continue to make progress with BOEM towards finalizing and implementing our long-term tailored plan. Currently, we have posted an aggregate of approximately $117,686 in surety bonds in favor of BOEM, third party bonds and letters of credit, all relating to our offshore abandonment obligations. A global update of the GOM decommissioning estimates was made on August 29, 2016, and BOEM requested that we resubmit our tailored plan to reflect the updated decommissioning estimates. The bonds represent guarantees

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by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements.

In July 2016, BOEM issued a Notice to Lessees ("NTL"), with an effective date of September 12, 2016, that augments requirements for the posting of additional financial assurances by offshore lessees. The NTL discontinues the policy of Supplemental Bonding Waivers and allows for the ability to self insure up to 10% of a company’s tangible net worth, where a company can demonstrate a certain level of financial strength. The NTL provides new procedures for how BOEM determines a lessee’s decommissioning obligations and, consistent with those procedures, BOEM has tentatively proposed an implementation timeline that offshore lessees will follow in providing additional financial assurance, including BOEM’s issuance of (i) "Self-Insurance" letters beginning September 12, 2016 (regarding a lessee’s ability to self-insure a portion of the additional financial assurance), (ii) "Proposal" letters beginning October 12, 2016 (outlining what amount of additional security a lessee will be required to provide), and (iii) "Order" letters beginning November 14, 2016 (triggering a lessee’s obligations (A) within 10 days of such letter to notify BOEM that it intends to pursue a "tailored plan" for posting additional security over a phased-in period of time, (B) within 60 days of such letter, provide additional security for "sole liability" properties (leases or grants for which there is no other current or prior owner who is liable for decommissioning obligations), and (C) within 120 days of such letter, provide additional security for any other properties and/or submit a tailored financial plan).

In connection with our exploration and development efforts, we are contractually committed to the use of drilling rigs and the acquisition of seismic data in the aggregate amount of $28,030 to be incurred over the next two years.

The Oil Pollution Act (the "OPA") imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA and a final rule adopted by the BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10,000 in specified state waters to at least $35,000 in Outer Continental Shelf ("OCS") waters, with higher amounts of up to $150,000 in certain limited circumstances where the BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the BOEM’s final rule. In addition, the BOEM has finalized rules that raise OPA's damages liability cap from $75,000 to $133,650.

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NOTE 16 — EMPLOYEE BENEFIT PLANS:

We have entered into deferred compensation and disability agreements with certain of our current and former officers. The benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2016, the liability for such vested benefits was approximately $961 and is recorded in current and other long-term liabilities. The deferred compensation plan is described further below.

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

Annual Cash Incentive Compensation Plans

The Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, provided for annual cash incentive bonuses tied to the achievement of certain strategic objectives as defined by our board of directors on an annual basis. For 2016, we replaced our historical long-term cash and equity-based incentive compensation programs with the 2016 Performance Incentive Compensation Plan (the "2016 Incentive Plan"), pursuant to which incentive cash bonuses are calculated based on the achievement of certain strategic objectives for each quarter of 2016. Stone incurred expenses of $13,475, $2,242, and $10,361, net of amounts capitalized, for each of the years ended December 31, 2016, 2015 and 2014, respectively, related to incentive compensation cash bonuses. See "Key Executive Incentive Plan" below for additional information.

Stock Incentive Plans

During 2016, we maintained the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (as Amended and Restated December 17, 2015), as amended from time to time (the "Amended 2009 Plan"). That plan was originally approved at the 2009 Annual Meeting of Stockholders (the "2009 Plan") and was an amendment and restatement of the Company’s 2004 Amended and Restated Stock Incentive Plan (the "2004 Plan"), and it superseded and replaced in its entirety the 2004 Plan. The Amended 2009 Plan provides for the granting of (a) "incentive" stock options as defined in Section 422 of the Code, (b) stock options that do not constitute incentive stock options ("non-statutory" stock options), (c) stock appreciation rights in conjunction with an incentive or non-statutory stock option, (d) restricted stock, (e) restricted stock units, (f) dividend equivalents, (g) other stock-based awards, (h) conversion awards, and (i) cash awards, any of which may be further designated as performance awards (collectively referred to as "awards"). The 2009 Plan eliminated the automatic grant of stock options or restricted stock awards to nonemployee directors that was provided for in the 2004 Plan so that awards under the 2009 Plan and the Amended 2009 Plan are entirely at the discretion of our board of directors or a designated committee. All options must have an exercise price of not less than the fair market value of our common stock on the date of grant and may not be re-priced without stockholder approval.

At the 2015 Annual Meeting of Stockholders, the stockholders approved the Second Amendment (the "Second Amendment") to the 2009 Plan and the Third Amendment (the "Third Amendment") to the 2009 Plan. The Second Amendment provided, among other things, for an increase in the number of shares of our common stock reserved for issuance under the 2009 Plan by 160,000 shares, effective May 21, 2015, and for an extension of the term of the 2009 Plan to May 21, 2025. The Third Amendment set forth the material terms of the 2009 Plan (i.e., the eligible employees, business criteria and maximum annual per person compensation limits) for purposes of complying with certain requirements of Section 162(m) of the Internal Revenue Code. The Third Amendment did not change the employees eligible to receive compensation under the 2009 Plan, but did (i) allow Stone to grant cash awards (which may or may not be designated as performance awards) under the 2009 Plan, (ii) impose a fixed share number limit on stock-based awards and a fixed dollar limit on cash awards granted during any calendar year under the 2009 Plan to certain individuals, and (iii) add additional business criteria that could be utilized in setting performance goals under the 2009 Plan. The Third Amendment also became effective as of May 21, 2015. On December 17, 2015, Stone amended and restated the 2009 Plan in the form of the Amended 2009 Plan to incorporate all prior amendments to the 2009 Plan (including the Second Amendment and the Third Amendment) and certain other non-material changes to the 2009 Plan.

At the 2016 Annual Meeting of Stockholders, the stockholders approved the adoption of the First Amendment (the "First Amendment") to the Amended 2009 Plan. The First Amendment increased the number of shares of our common stock reserved for issuance under the Amended 2009 Plan by 45,000 shares (as adjusted to reflect our June 2016 reverse stock split), effective May 19, 2016. The stockholders also approved the material terms of the Amended 2009 Plan, as amended by the First Amendment (i.e., the eligible employees, business criteria and maximum annual per person compensation limits) for purposes of complying with certain requirements of Section 162(m) of the Internal Revenue Code.

At December 31, 2016, we had approximately 237,062 additional shares available for issuance pursuant to the Stock Incentive Plan. We have adopted the Stone Energy Corporation 2017 Long-Term Incentive Plan, which is an omnibus equity compensation plan that will replace the Amended 2009 Plan and will become effective upon our emergence from bankruptcy.

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401(k) and Deferred Compensation Plans

The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 2016, 2015 and 2014, Stone contributed $1,248, $1,553 and $1,989, respectively, to the plan.

The Stone Energy Corporation Deferred Compensation Plan provides eligible executives and employees with the option to defer up to 100% of their eligible compensation for a calendar year and we could, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by our board of directors. In addition, the Board may elect to make discretionary profit sharing contributions to the plan. To date there have been no matching or discretionary profit sharing contributions made by Stone, and in connection with our entry into the Settlement Agreement (defined below), we adopted an amendment to the Deferred Compensation Plan that removed our ability to make matching contributions under that plan. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At December 31, 2016 and 2015, plan assets of $8,746 and $8,499, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.

Change of Control and Severance Plans

On April 7, 2009, we amended and restated our Executive Change of Control and Severance Plan effective as of December 31, 2008 (as so amended and restated, the "Executive Plan"). The Executive Plan also replaced and superseded our Executive Change in Control and Severance Policy that was maintained for certain designated executives (specifically, the CEO and CFO). The Executive Plan provided the Company’s officers terminated in the event of a change of control and upon certain other terminations of employment with change of control and severance benefits as defined in the Executive Plan. Although our CEO did not participate in the Executive Plan, the severance benefits provided to him under his employment agreement were substantially similar to the benefits provided under the Executive Plan. Executives terminated within the scope of the Executive Plan (or their applicable employment agreement) were entitled to certain payments and benefits including the following: (i) any unpaid base salary up to the date of termination; (ii) in the case of the CEO and CFO, a lump sum severance payment of 2.99 times the sum of the executive’s annual base salary and any target bonus at the one hundred percent level; (iii) a lump sum amount representing a pro rata share of the bonus opportunity up to the date of termination at the then projected rate of payout; (iv) in the case of officers other than the CEO and CFO and an involuntary termination occurring outside a change of control period, a lump sum severance payment in an amount equal to the executive’s annual base salary; (v) in the case of officers other than the CEO and CFO and an involuntary termination occurring during a change of control period, a lump sum severance payment in an amount equal to 2.99 times the executive’s annual base salary; and (vi) continued health plan coverage for six months and outplacement services. In the case of the CEO and CFO, if the payments would be "excess parachute payments," the CEO and CFO could receive a potential gross-up payment to reimburse them for excise taxes that might be incurred under Section 4999 of the Internal Revenue Code of 1986, as amended (the "Code"), as well as any additional income taxes resulting from such reimbursement, provided that if it was determined that the executive would be entitled to a gross-up payment but the total to be paid would not exceed 110% of the greatest amount (the "Reduced Amount") that could be paid such that receipt of the total would not give rise to any excise tax, then no gross-up would be paid and the total payments to the executive would be reduced to the Reduced Amount. Also, if a payment would be to a "specified employee" for purposes of Section 409A of the Code, payment would be delayed until six months after his termination if required to comply with Section 409A. Benefits paid upon a change of control, without regard to whether there is a termination of employment, included the following: (i) lapse of restrictions on restricted stock, (ii) accelerated vesting and cash-out of all in-the-money stock options, (iii) a 401(k) plan employer matching contribution at the rate of 50%, and (iv) a pro-rated portion of the projected bonus, if any, for the year of change of control.

On December 13, 2016, the Company entered into an Executive Claims Settlement Agreement (the "Settlement Agreement") with nine members of the Company’s senior executive team (collectively, the "Senior Executives"), subject to approval by the Bankruptcy Court, which occurred on January 10, 2017. The Settlement Agreement provides for the termination of the Executive Plan and the employment agreement entered into with Kenneth H. Beer and the modification of the employment agreements with David H. Welch and Richard L. Toothman, Jr. In connection with the Settlement Agreement, we adopted the Stone Energy Corporation Executive Severance Plan (the "Executive Severance Plan") in which all Senior Executives are allowed to participate. Pursuant to the terms of the Executive Severance Plan, severance payable to each of the Senior Executives remains substantially similar to the prior arrangements, with the exception that (a) the severance amounts payable to each of David H. Welch and Kenneth H. Beer have been reduced from 2.99x annual base salary and target bonus to (i) for Mr. Welch, 1.5x annual base salary and 1.0x the bonus permitted under the Key Executive Incentive Plan ("KEIP"), and (ii) for Mr. Beer, 1.25x annual base salary and 1.0x the bonus permitted under the KEIP; (b) six months of health benefit continuation; (c) all holders of equity awards subject to vesting will automatically vest in the next tranche of time-based equity that would be scheduled to vest; (d) certain outplacement

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services; and (e) all Section 280G gross-up payments to which Senior Executives may have previously been entitled were eliminated in favor of a reduction of payments and/or benefits to each Senior Executive in whole or in part only, if by such reduction, the applicable Senior Executive’s net after-tax benefit will exceed such Senior Executive’s net after-tax benefit if such reductions were not made. Further, the Settlement Agreement amends the employment agreement entered into by the Company with David H. Welch (the "Welch Employment Agreement"), pursuant to which Mr. Welch waives any rights to severance under the Welch Employment Agreement in exchange for participation in the Executive Severance Plan. Mr. Toothman also participates in the Executive Severance Plan but remains eligible to receive special severance benefits if he incurs a qualifying termination of employment in connection with the disposition of the Appalachia Properties.

On December 7, 2007, our board of directors approved and adopted the Stone Energy Corporation Employee Change of Control Severance Plan ("Employee Severance Plan"), as amended and restated to comply with the final regulations under Section 409A of the Code and to provide that said plan will remain in force and effect unless and until terminated by our board of directors. The Employee Severance Plan amended and restated the Company’s previous Employee Change of Control Severance Plan dated November 16, 2006. The Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the six-month period following a change of control, including a resignation by the employee relating to a change in duties. Employees who are terminated within the scope of the Employee Severance Plan will be entitled to certain payments and benefits including the following: (i) a lump sum equal to (1) weekly pay times full years of service, plus (2) one week’s pay for each full $10,000 of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay; (ii) continued health plan coverage for 6 months; (iii) a pro-rated portion of the employee’s targeted bonus for the year, and (iv) reasonable outplacement services consistent with current HR practices. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: (i) lapse of restrictions on restricted stock, (ii) cash-out of in-the-money stock options, (iii) a 401(k) plan employer matching contribution at the rate of 50%, and (iv) a lump sum cash payment equal to the product of (1) the number of "restricted shares" of company stock that the employee would have received under the company’s stock plan but did not receive for the time-vested portion of his long-term stock incentive award, if any, for the calendar year in which the change of control occurs times (2) the price per share of the company’s common stock utilized in effecting the change of control, provided that such amount shall be pro-rated by multiplying such amount by the number of full months that have elapsed from January 1 of that calendar year to the effective date of the change of control and then dividing the result by 12.

Key Executive Incentive Plan

Pursuant to the terms of the Settlement Agreement, the Senior Executives agreed to waive their claims related to the Company’s existing 2016 Incentive Plan, and in exchange therefor, we adopted the Stone Energy Corporation Key Executive Incentive Plan ("KEIP"), in which the Senior Executives are allowed to participate. The Senior Executives no longer have a fourth quarter bonus opportunity under the 2016 Incentive Plan and future payments to Senior Executives under the KEIP shall not be paid until the consummation of the Bankruptcy Cases and are limited to approximately $2,000, or the equivalent of the target bonus under the 2016 Incentive Plan for the fourth quarter of 2016. Future payments to Senior Executives under the KEIP shall be paid 50% upon consummation of the bankruptcy cases and 50% 90 days after the Company exits bankruptcy; provided, however, the Senior Executives must be employed upon consummation of the bankruptcy cases and the 90th day following the Company’s exit from bankruptcy or be terminated without cause in order to receive the respective bonus.

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NOTE 17 — SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED:

At December 31, 2016, 2015 and 2014, our oil and gas properties were located in the United States and Canada.

Costs Incurred

The following table discloses certain financial data relative to our oil and gas producing activities located onshore and offshore in the continental United States:



	Year Ended December 31,
	2016			2015			2014
Oil and gas properties – United States, proved and unevaluated:
Balance, beginning of year	$	9,773,457		$	9,348,054		$	8,517,873
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties	3,923			(14,158		)	44,634
Exploratory costs	17,891			104,169			270,850
Development costs (1)	102,665			266,982			438,334
Salaries, general and administrative costs	21,753			27,984			33,975
Interest	26,634			41,339			45,722
Less: overhead reimbursements	(521		)	(913		)	(3,334		)
Total costs incurred during the year, net of divestitures	172,345			425,403			830,181
Balance, end of year	$	9,945,802		$	9,773,457		$	9,348,054
Accumulated DD&A:
Balance, beginning of year	$	(8,561,472	)	$	(6,970,631	)	$	(5,908,760	)
Provision for DD&A	(215,737		)	(277,088		)	(335,987		)
Write-down of oil and gas properties	(357,079		)	(1,314,817		)	(351,192		)
Sale of proved properties	—			1,064			(374,692		)
Balance, end of year	$	(9,134,288	)	$	(8,561,472	)	$	(6,970,631	)
Net capitalized costs – United States, proved and unevaluated	$	811,514		$	1,211,985		$	2,377,423
DD&A per Mcfe	$	2.68		$	3.19		$	3.59

(1) Includes capitalized asset retirement costs of ($4,461), ($43,901) and ($20,305), respectively.



Costs incurred during the year (expensed):
Lease operating expenses	$	79,650	$	100,139	$	176,495
Transportation, processing and gathering expenses	27,760		58,847		64,951
Production taxes	3,148		6,877		12,151
Accretion expense	40,229		25,988		28,411
Expensed costs – United States	$	150,787	$	191,851	$	282,008

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 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, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $128,852 based on twelve-month average prices, net of applicable differentials, of $46.72 per Bbl of oil, $2.01 per Mcf of natural gas and $13.65 per Bbl of NGLs. At March 31, 2016, the write-down of oil and gas properties also included $352 related to our Canadian oil and gas properties, which were deemed to be fully impaired at the end of 2015. At June 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $118,649 based on twelve-month average prices, net of applicable differentials,

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of $43.49 per Bbl of oil, $1.93 per Mcf of natural gas and $9.33 per Bbl of NGLs. At September 30, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $36,484 based on twelve-month average prices, net of applicable differentials, of $40.51 per Bbl of oil, $1.99 per Mcf of natural gas and $13.88 per Bbl of NGLs. At December 31, 2016, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $73,094 based on twelve-month average prices, net of applicable differentials, of $40.15 per Bbl of oil, $1.71 per Mcf of natural gas and $9.46 per Bbl of NGLs. The March 31, June 30 and September 30, 2016 write-downs were decreased by $22,986, $18,112 and $9,636, respectively, as a result of hedges. There was no hedging impact on the December 31, 2016 write-down.

At March 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $491,412 based on twelve-month average prices, net of applicable differentials, of $78.99 per Bbl of oil, $2.96 per Mcf of natural gas and $28.82 per Bbl of NGLs. At June 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $179,125 based on twelve-month average prices, net of applicable differentials, of $68.68 per Bbl of oil, $2.47 per Mcf of natural gas and $29.13 per Bbl of NGLs. At September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $295,679 based on twelve-month average prices, net of applicable differentials, of $57.76 per Bbl of oil, $2.44 per Mcf of natural gas and $23.04 per Bbl of NGLs. At December 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $348,601 based on twelve-month average prices, net of applicable differentials, of $51.16 per Bbl of oil, $2.19 per Mcf of natural gas and $16.40 per Bbl of NGLs. The March 31, June 30, September 30 and December 31, 2015 write-downs were decreased by $28,687, $47,784, $42,652 and $24,797, respectively, as a result of hedges.

At September 30, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $47,130 based on twelve-month average prices, net of applicable differentials, of $94.94 per Bbl of oil, $4.19 per Mcf of natural gas and $41.33 per Bbl of NGLs. At December 31, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $304,062 based on twelve-month average prices, net of applicable differentials, of $89.46 per Bbl of oil, $3.68 per Mcf of natural gas and $36.79 per Bbl of NGLs. The September 30 and December 31, 2014 write-downs were increased by $29,001 and $13,342, respectively, as a result of hedges.

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



	Year Ended December 31,
Unevaluated oil and gas properties – United States:	2016			2015			2014
Net costs incurred (evaluated) during year:
Acquisition costs	$	(71,378	)	$	(115,767	)	$	(42,384	)
Exploration costs	(21,579		)	(16,315		)	(186,308		)
Capitalized interest	26,634			41,339			45,722
	$	(66,323	)	$	(90,743	)	$	(182,970	)

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

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	Year Ended December 31,
	2016			2015			2014
Oil and gas properties – Canada:
Balance, beginning of year	$	42,484		$	36,579		$	10,583
Costs incurred during the year (capitalized):
Acquisition costs	(498		)	(2,862		)	6,956
Exploratory costs	2,168			8,767			19,040
Total costs incurred during the year	1,670			5,905			25,996
Balance, end of year (fully evaluated at December 31, 2016 and 2015 and unevaluated at December 31, 2014)	$	44,154		$	42,484		$	36,579
Accumulated DD&A:
Balance, beginning of year	$	(42,484	)	$	—		$	—
Foreign currency translation adjustment	(1,318		)	5,146			—
Write-down of oil and gas properties	(352		)	(47,630		)	—
Balance, end of year	$	(44,154	)	$	(42,484	)	$	—
Net capitalized costs – Canada	$	—		$	—		$	36,579

The following table discloses financial data associated with unevaluated costs (United States) at December 31, 2016:



	Balance as of		Net Costs Incurred During the Year Ended December 31,
	December 31, 2016		2016		2015		2014		2013 and prior
Acquisition costs	$	122,589	$	8,278	$	17,308	$	47,490	$	49,513
Exploration costs	153,320		34,183		38,686		42,298		38,153
Capitalized interest	97,811		24,759		33,232		32,287		7,533
Total unevaluated costs	$	373,720	$	67,220	$	89,226	$	122,075	$	95,199

Approximately 73 specifically identified drilling projects are included in unevaluated costs at December 31, 2016 and are expected to be evaluated in the next four years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs capitalized on unevaluated properties during the years ended December 31, 2016, 2015 and 2014 totaled $26,634, $41,339 and $45,722, respectively.

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2016 have been prepared in accordance with guidelines established by the Securities and Exchange Commission ("SEC"). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

The following table sets forth an analysis of the estimated quantities of net proved oil (including condensate), natural gas and NGL reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil, natural gas and NGL reserves at December 31, 2016, 2015 and 2014 are prepared in accordance with the SEC’s rule, "Modernization of Oil and Gas Reporting," using a historical twelve-month average pricing assumption.

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	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Oil, Natural Gas and NGLs (MMcfe)
Estimated proved reserves as of December 31, 2013	43,827		23,297		460,766		863,513
Revisions of previous estimates	(624	)	(331	)	(4,631	)	(10,362	)
Extensions, discoveries and other additions	9,650		7,521		131,617		234,639
Sale of reserves	(4,888	)	(556	)	(46,483	)	(79,151	)
Production	(5,568	)	(2,114	)	(47,426	)	(93,515	)
Estimated proved reserves as of December 31, 2014	42,397		27,817		493,843		915,124
Revisions of previous estimates	(6,818	)	(20,777	)	(362,102	)	(527,675	)
Extensions, discoveries and other additions	862		11		1,499		6,738
Purchase of producing properties	685		1,808		26,136		41,095
Sale of reserves	(859	)	—		(1,061	)	(6,213	)
Production	(5,991	)	(2,401	)	(36,457	)	(86,809	)
Estimated proved reserves as of December 31, 2015	30,276		6,458		121,858		342,260
Revisions of previous estimates	(751	)	6,352		24,858		58,465
Extensions, discoveries and other additions	63		2		45		435
Production	(6,308	)	(2,183	)	(29,441	)	(80,387	)
Estimated proved reserves as of December 31, 2016	23,280		10,629		117,320		320,773
Estimated proved developed reserves:
as of December 31, 2014	22,957		13,743		249,924		470,118
as of December 31, 2015	21,734		4,784		90,262		249,366
as of December 31, 2016	18,269		9,255		90,741		255,884
Estimated proved undeveloped reserves:
as of December 31, 2014	19,440		14,074		243,919		445,006
as of December 31, 2015	8,542		1,674		31,596		92,894
as of December 31, 2016	5,011		1,374		26,579		64,889

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

Year Ended December 31, 2016. Revisions of previous estimates were primarily the result of positive reserve report gas pricing changes extending the economic limits of the reservoirs (92 Bcfe) primarily in Appalachia, slightly offset by negative well performance (35 Bcfe).

Year Ended December 31, 2015. Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves (570 Bcfe) primarily in Appalachia, slightly offset by positive well performance (42 Bcfe). Purchase of producing properties related to increases in our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units.

Year Ended December 31, 2014. Extensions, discoveries and other additions were primarily the result of our Appalachia (118 Bcfe) and our deep water (116 Bcfe) drilling programs. Sale of reserves primarily related to the sale of certain of our non-core GOM conventional shelf properties (63 Bcfe) and our Katie field in Appalachia (15 Bcfe).

Standardized Measure of Discounted Future Net Cash Flow

The following tables present the standardized measure of discounted future net cash flows related to estimated proved oil, natural gas and NGL reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2016. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil, natural gas and NGL reserves. Prices are based on either the historical twelve-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The 2016 average historical twelve-month oil and natural gas prices, net of applicable differentials, were $40.15 per Bbl of oil, $9.46 per Bbl of NGLs and $1.71 per Mcf of natural

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gas. The 2015 average twelve-month oil and natural gas prices, net of applicable differentials, were $51.16 per Bbl of oil, $16.40 per Bbl of NGLs and $2.19 per Mcf of natural gas. The 2014 average twelve-month oil and natural gas prices, net of applicable differentials, were $89.46 per Bbl of oil, $36.79 per Bbl of NGLs and $3.68 per Mcf of natural gas. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. Our GOM Basin properties represented approximately 66% of our estimated proved oil and natural gas reserves and virtually all of the standardized measure of discounted future net cash flows at December 31, 2016.



	Standardized Measure Year Ended December 31,
	2016			2015			2014
Future cash inflows	$	1,236,097		$	1,921,329		$	6,635,751
Future production costs	(480,815		)	(651,396		)	(2,413,004		)
Future development costs	(638,988		)	(679,355		)	(1,511,687		)
Future income taxes	—			—			(609,516		)
Future net cash flows	116,294			590,578			2,101,544
10% annual discount	109,628			13,259			(682,752		)
Standardized measure of discounted future net cash flows	$	225,922		$	603,837		$	1,418,792



	Changes in Standardized Measure Year Ended December 31,
	2016			2015			2014
Standardized measure at beginning of year	$	603,837		$	1,418,792		$	1,685,002
Sales and transfers of oil, natural gas and NGLs produced, net of production costs	(223,948		)	(340,477		)	(486,232		)
Changes in price, net of future production costs	(448,861		)	(237,747		)	(864,118		)
Extensions and discoveries, net of future production and development costs	5,243			1,573			549,649
Changes in estimated future development costs, net of development costs incurred during the period	54,406			731,115			203,026
Revisions of quantity estimates	139,759			(1,458,652		)	(27,495		)
Accretion of discount	60,384			174,456			222,009
Net change in income taxes	—			325,768			209,323
Purchases of reserves in-place	—			3,493			—
Sales of reserves in-place	—			—			(152,787		)
Changes in production rates due to timing and other	35,102			(14,484		)	80,415
Net decrease in standardized measure	(377,915		)	(814,955		)	(266,210		)
Standardized measure at end of year	$	225,922		$	603,837		$	1,418,792

NOTE 18 — OTHER OPERATIONAL EXPENSES:

Included in other operational expenses for the year ended December 31, 2016 is a $6,081 loss on the liquidation of our former foreign subsidiary, Stone Energy Canada ULC, representing cumulative foreign currency translation adjustments, which were reclassified from accumulated other comprehensive income. See Note 12 – Accumulated Other Comprehensive Income (Loss). Also included in other operational expenses for the year ended December 31, 2016 are approximately $17,741 of rig subsidy and stacking charges related to the ENSCO 8503 deep water drilling rig, an Appalachian drilling rig and the platform rig at Pompano, a $20,000 charge related to the termination of our deep water drilling rig contract with Ensco and $9,889 in charges related to the terminations of the Appalachian drilling rig contract and contracts with two GOM vendors.

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NOTE 19 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED:

The results of operations by quarter are as follows:



	2016
	Quarter Ended
	March 31			June 30			September 30			December 31
Operating revenue	$	80,677		$	89,319		$	94,427		$	113,107
Loss from operations	(172,150		)	(174,656		)	(72,128		)	(90,234		)
Net loss	(188,784		)	(195,761		)	(89,635		)	(116,406		)
Basic loss per share	$	(33.89	)	$	(35.05	)	$	(16.01	)	$	(20.76	)
Diluted loss per share	$	(33.89	)	$	(35.05	)	$	(16.01	)	$	(20.76	)

Write-down of oil and gas properties	$	129,204		$	118,649		$	36,484		$	73,094
Restructuring fees	$	953		$	9,436		$	5,784		$	13,424
Other operational expenses (1)	$	12,527		$	27,680		$	9,059		$	6,187
Reorganization items	—			—			—			$	10,947

(1) See Note 18 – Other Operational Expenses for additional details.



	2015
	Quarter Ended
	March 31			June 30			September 30			December 31
Operating revenue	$	153,498		$	149,525		$	132,196		$	110,499
Loss from operations	(497,194		)	(228,161		)	(297,209		)	(342,759		)
Net loss	(327,388		)	(152,906		)	(291,965		)	(318,656		)
Basic loss per share	$	(59.33	)	$	(27.68	)	$	(52.82	)	$	(57.63	)
Diluted loss per share	$	(59.33	)	$	(27.68	)	$	(52.82	)	$	(57.63	)

Write-down of oil and gas properties	$	491,412		$	224,294		$	295,679		$	351,062

NOTE 20 — NEW YORK STOCK EXCHANGE COMPLIANCE:

On April 29, 2016, we were notified by the New York Stock Exchange ("NYSE") that we were not in compliance with the NYSE's continued listing requirements, as the average closing price of our shares of common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price for continued listing on the NYSE under Section 802.01C of the NYSE Listed Company Manual. On May 17, 2016, we were notified by the NYSE that our average global market capitalization had been less than $50,000 over a consecutive 30 trading-day period at the same time that our stockholders' equity was less than $50,000, which is non-compliant with Section 802.01B of the NYSE Listed Company Manual.

At the close of business on June 10, 2016, we effected a 1-for-10 reverse stock split (see Note 1 – Organization and Summary of Significant Accounting Policies) in order to increase the market price per share of our common stock in order to regain compliance with the NYSE's minimum share price requirement. We were notified on July 1, 2016 that we cured the minimum share price deficiency and that we were no longer considered non-compliant with the $1.00 per share average closing price requirement. We remain non-compliant with the $50,000 market capitalization and stockholders' equity requirements

On June 30, 2016, we submitted our 18-month business plan for curing the average market capitalization and stockholders' equity deficiencies to the NYSE. The NYSE accepted the plan on August 4, 2016 and will continue to review the Company on a quarterly basis for compliance with the plan. Upon acceptance of the plan by the NYSE, and after two consecutive quarters of sustained market capitalization above $50,000, we would no longer be non-compliant with the market capitalization and stockholders' equity requirements. During the 18-month cure period, our shares of common stock will continue to be listed and traded on the NYSE, unless we experience other circumstances that subject us to delisting, including an abnormally low market

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capitalization. If we fail to meet the material aspects of the plan or any of the quarterly milestones, the NYSE will review the circumstances causing the variance and determine whether such variance warrants commencement of suspension and delisting procedures. Additionally, under Section 802.01D of the NYSE Listed Company Manual, if a company that is below a continued listing standard files or announces an intent to file for relief under Chapter 11 of the Bankruptcy Code, the company is subject to immediate suspension and delisting. However, if we are profitable or have positive cash flow, or if we are demonstrably in sound financial health despite the bankruptcy proceedings, the NYSE may evaluate our plan in light of the filing without immediate suspension and delisting of our common stock. To date, and throughout the Chapter 11 filing period, we have continued to trade on the NYSE.

On September 20, 2016, we submitted our quarterly update to the business plan for the second quarter of 2016, and the NYSE notified us that it accepted the quarterly update on September 22, 2016. On December 22, 2016, we submitted our quarterly update to the business plan for the third quarter of 2016, and the NYSE notified us that it accepted the quarterly update on January 5, 2017. We expect to submit our fourth quarter 2016 plan update to the NYSE by mid-March 2017.

NOTE 21 — SUBSEQUENT EVENTS:

Confirmation of Plan of Reorganization

On February 15, 2017, the Bankruptcy Court entered an order confirming the Plan. See Note 2 – Chapter 11 Proceedings.

Disposition of Appalachia Properties

Pursuant to Bankruptcy Court orders dated January 11, 2017 and January 31, 2017, two additional bidders were allowed to participate in competitive bidding on the Appalachia Properties. See Note 2 – Chapter 11 Proceedings. On January 18, 2017, the Bankruptcy Court approved the Bidding Procedures in connection with the sale of the Appalachia Properties. In accordance with the Bidding Procedures, Stone conducted an auction for the sale of the Appalachia Properties on February 8, 2017 and upon conclusion, selected the final bid submitted by EQT, with a final purchase price of $527,000 in cash, subject to customary purchase price adjustments and approval by the Bankruptcy Court, with an upward adjustment to the purchase price of up to $16,000 in an amount equal to certain downward adjustments, as the prevailing bid.

On February 9, 2017, the Company entered into a purchase and sale agreement with EQT (the "EQT PSA"), reflecting the terms of the prevailing bid. Under the EQT PSA, the sale of the Appalachia Properties has an effective date of June 1, 2016. The EQT PSA contains customary representations, warranties and covenants. From and after the closing of the sale of the Appalachia Properties, the Company and EQT, respectively, have agreed to indemnify each other and their respective affiliates against certain losses resulting from any breach of their representations, warranties or covenants contained in the EQT PSA, subject to certain customary limitations and survival periods. Additionally, from and after closing of the sale of the Appalachia Properties, the Company has agreed to indemnify EQT for certain identified retained liabilities related to the Appalachia Properties, subject to certain survival periods, and EQT has agreed to indemnify the Company for certain assumed obligations related to the Appalachia Properties. The EQT PSA may be terminated, subject to certain exceptions, (i) upon mutual written consent, (ii) if the closing has not occurred by March 1, 2017, (iii) for certain material breaches of representations and warranties or covenants that remain uncured and (iv) upon the occurrence of certain other events specified in the EQT PSA.

At the close of the sale of the Appalachia Properties, the Tug Hill PSA will terminate, and the Company will use a portion of the cash consideration received to pay Tug Hill a break-up fee of $10,800. On February 10, 2017, the Bankruptcy Court entered a sale order approving the sale of the Appalachia Properties to EQT. We expect to close the sale of the Appalachia Properties by February 28, 2017, subject to customary closing conditions. At December 31, 2016, the Appalachia Properties accounted for approximately 34% of our total estimated proved oil and natural gas reserves on a volume equivalent basis.

NOTE 22 — GUARANTOR FINANCIAL STATEMENTS:

Stone Offshore is an unconditional guarantor (the "Guarantor Subsidiary") of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the "Non-Guarantor Subsidiaries") have not provided guarantees. The following presents consolidating financial information as of December 31, 2016 and 2015 and for the years ended December 31, 2016, 2015 and 2014 on an issuer (parent company), Guarantor Subsidiary, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

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CCONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2016

(In thousands)



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	150,537		$	40,044		$	—		$	—		$	190,581
Accounts receivable	18,745			31,452			—			(1,733		)	48,464
Current income tax receivable	26,086			—			—			—			26,086
Other current assets	10,151			—			—			—			10,151
Total current assets	205,519			71,496			—			(1,733		)	275,282
Oil and gas properties, full cost method:
Proved	1,964,046			7,608,036			44,154			—			9,616,236
Less: accumulated DD&A	(1,964,046		)	(7,170,242		)	(44,154		)	—			(9,178,442		)
Net proved oil and gas properties	—			437,794			—			—			437,794
Unevaluated	251,955			121,765			—			—			373,720
Other property and equipment, net	26,213			—			—			—			26,213
Other assets, net	25,570			904			—			—			26,474
Investment in subsidiary	389,475			76			—			(389,551		)	—
Total assets	$	898,732		$	632,035		$	—		$	(391,284	)	$	1,139,483
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	13,742		$	7,972		$	—		$	(1,733	)	$	19,981
Undistributed oil and gas proceeds	14,170			903			—			—			15,073
Accrued interest	809			—			—			—			809
Asset retirement obligations	—			88,000			—			—			88,000
Current portion of long-term debt	408			—			—			—			408
Other current liabilities	18,602			—			—			—			18,602
Total current liabilities	47,731			96,875			—			(1,733		)	142,873
Long-term debt	352,376			—			—			—			352,376
Asset retirement obligations	8,410			145,609			—			—			154,019
Other long-term liabilities	17,315			—			—			—			17,315
Total liabilities not subject to compromise	425,832			242,484			—			(1,733		)	666,583
Liabilities subject to compromise	1,110,182			—			—			—			1,110,182
Total liabilities	1,536,014			242,484			—			(1,733		)	1,776,765
Commitments and contingencies
Stockholders’ equity:
Common stock	56			—			—			—			56
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,659,731			1,300,547			108,198			(1,408,745		)	1,659,731
Accumulated deficit	(2,296,209		)	(910,996		)	(108,198		)	1,019,194			(2,296,209		)
Total stockholders’ equity	(637,282		)	389,551			—			(389,551		)	(637,282		)
Total liabilities and stockholders’ equity	$	898,732		$	632,035		$	—		$	(391,284	)	$	1,139,483

F-42

Table of Contents

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2015

(In thousands)



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,681		$	2		$	1,076		$	—		$	10,759
Accounts receivable	10,597			39,190			—			(1,756		)	48,031
Fair value of derivative contracts	—			38,576			—			—			38,576
Current income tax receivable	46,174			—			—			—			46,174
Other current assets	6,848			—			33			—			6,881
Total current assets	73,300			77,768			1,109			(1,756		)	150,421
Oil and gas properties, full cost method:
Proved	1,875,152			7,458,262			42,484			—			9,375,898
Less: accumulated DD&A	(1,874,622		)	(6,686,849		)	(42,484		)	—			(8,603,955		)
Net proved oil and gas properties	530			771,413			—			—			771,943
Unevaluated	253,308			186,735			—			—			440,043
Other property and equipment, net	29,289			—			—			—			29,289
Other assets, net	16,612			826			1,035			—			18,473
Investment in subsidiary	745,033			—			1,088			(746,121		)	—
Total assets	$	1,118,072		$	1,036,742		$	3,232		$	(747,877	)	$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	16,063		$	67,901		$	—		$	(1,757	)	$	82,207
Undistributed oil and gas proceeds	5,216			776			—			—			5,992
Accrued interest	9,022			—			—			—			9,022
Asset retirement obligations	—			20,400			891			—			21,291
Other current liabilities	40,161			551			—			—			40,712
Total current liabilities	70,462			89,628			891			(1,757		)	159,224
Long-term debt	1,060,955			—			—			—			1,060,955
Asset retirement obligations	1,240			203,335			—			—			204,575
Other long-term liabilities	25,204			—			—			—			25,204
Total liabilities	1,157,861			292,963			891			(1,757		)	1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock	55			—			—			—			55
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,648,687			1,344,577			109,795			(1,454,372		)	1,648,687
Accumulated deficit	(1,705,623		)	(624,824		)	(95,306		)	720,130			(1,705,623		)
Accumulated other comprehensive income (loss)	17,952			24,026			(12,148		)	(11,878		)	17,952
Total stockholders’ equity	(39,789		)	743,779			2,341			(746,120		)	(39,789		)
Total liabilities and stockholders’ equity	$	1,118,072		$	1,036,742		$	3,232		$	(747,877	)	$	1,410,169

F-43

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2016

(In thousands)



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	9,268		$	271,978		$	—		$	—		$	281,246
Natural gas production	25,276			39,325			—			—			64,601
Natural gas liquids production	22,142			6,746			—			—			28,888
Other operational income	2,657			—			—			—			2,657
Total operating revenue	59,343			318,049			—			—			377,392
Operating expenses:
Lease operating expenses	12,048			67,589			13			—			79,650
Transportation, processing, and gathering expenses	28,091			(331		)	—			—			27,760
Production taxes	2,387			761			—			—			3,148
Depreciation, depletion, amortization	67,059			153,020			—			—			220,079
Write-down of oil and gas properties	26,706			330,373			352			—			357,431
Accretion expense	232			39,997			—			—			40,229
Salaries, general and administrative expenses	59,127			(199		)	—			—			58,928
Incentive compensation expense	13,475			—			—			—			13,475
Restructuring fees	29,597			—			—			—			29,597
Other operational expenses	49,247			125			6,081			—			55,453
Derivative expense, net	—			810			—			—			810
Total operating expenses	287,969			592,145			6,446			—			886,560
Loss from operations	(228,626		)	(274,096		)	(6,446		)	—			(509,168		)
Other (income) expenses:
Interest expense	64,458			—			—			—			64,458
Interest income	(503		)	(47		)	—			—			(550		)
Other income	(482		)	(957		)	—			—			(1,439		)
Other expense	596			—			—			—			596
Reorganization items	10,947			—			—			—			10,947
Loss from investment in subsidiaries	292,618			—			6,446			(299,064		)	—
Total other (income) expenses	367,634			(1,004		)	6,446			(299,064		)	74,012
Loss before taxes	(596,260		)	(273,092		)	(12,892		)	299,064			(583,180		)
Provision (benefit) for income taxes:
Current	(5,674		)	—			—			—			(5,674		)
Deferred	—			13,080			—			—			13,080
Total income taxes	(5,674		)	13,080			—			—			7,406
Net loss	$	(590,586	)	$	(286,172	)	$	(12,892	)	$	299,064		$	(590,586	)
Comprehensive loss	$	(608,538	)	$	(286,172	)	$	(12,892	)	$	299,064		$	(608,538	)

F-44

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2015

(In thousands)



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	12,804		$	403,693		$	—		$	—		$	416,497
Natural gas production	41,646			41,863			—			—			83,509
Natural gas liquids production	22,375			9,947			—			—			32,322
Other operational income	4,369			—			—			—			4,369
Derivative income, net	—			7,952			—			—			7,952
Total operating revenue	81,194			463,455			—			—			544,649
Operating expenses:
Lease operating expenses	16,264			83,872			3			—			100,139
Transportation, processing, and gathering expenses	50,247			8,600			—			—			58,847
Production taxes	5,631			1,246			—			—			6,877
Depreciation, depletion, amortization	123,724			157,964			—			—			281,688
Write-down of oil and gas properties	785,463			529,354			47,630			—			1,362,447
Accretion expense	365			25,623			—			—			25,988
Salaries, general and administrative expenses	69,147			201			36			—			69,384
Incentive compensation expense	2,242			—			—			—			2,242
Other operational expenses	2,360			—			—			—			2,360
Total operating expenses	1,055,443			806,860			47,669			—			1,909,972
Loss from operations	(974,249		)	(343,405		)	(47,669		)	—			(1,365,323		)
Other (income) expenses:
Interest expense	43,907			21			—			—			43,928
Interest income	(327		)	(246		)	(7		)	—			(580		)
Other income	(617		)	(1,163		)	(3		)	—			(1,783		)
Other expense	434			—			—			—			434
Loss from investment in subsidiaries	231,783			—			47,659			(279,442		)	—
Total other (income) expenses	275,180			(1,388		)	47,649			(279,442		)	41,999
Loss before taxes	(1,249,429		)	(342,017		)	(95,318		)	279,442			(1,407,322		)
Provision (benefit) for income taxes:
Current	(44,096		)	—			—			—			(44,096		)
Deferred	(114,418		)	(157,893		)	—			—			(272,311		)
Total income taxes	(158,514		)	(157,893		)	—			—			(316,407		)
Net loss	$	(1,090,915	)	$	(184,124	)	$	(95,318	)	$	279,442		$	(1,090,915	)
Comprehensive loss	$	(1,156,278	)	$	(184,124	)	$	(95,318	)	$	279,442		$	(1,156,278	)

F-45

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014

(In thousands)



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	29,701		$	486,403		$	—		$	—		$	516,104
Natural gas production	86,812			79,682			—			—			166,494
Natural gas liquids production	61,200			24,442			—			—			85,642
Other operational income	7,551			400			—			—			7,951
Derivative income, net	—			19,351			—			—			19,351
Total operating revenue	185,264			610,278			—			—			795,542
Operating expenses:
Lease operating expenses	18,719			157,776			—			—			176,495
Transportation, processing and gathering expenses	53,028			11,923			—			—			64,951
Production taxes	8,324			3,827			—			—			12,151
Depreciation, depletion, amortization	138,313			201,693			—			—			340,006
Write-down of oil and gas properties	351,192			—			—			—			351,192
Accretion expense	230			28,181			—			—			28,411
Salaries, general and administrative expenses	66,430			4			17			—			66,451
Incentive compensation expense	10,361			—			—			—			10,361
Other operational expenses	669			193			—			—			862
Total operating expenses	647,266			403,597			17			—			1,050,880
Income (loss) from operations	(462,002		)	206,681			(17		)	—			(255,338		)
Other (income) expenses:
Interest expense	38,810			45			—			—			38,855
Interest income	(333		)	(192		)	(49		)	—			(574		)
Other income	(836		)	(1,496		)	—			—			(2,332		)
Other expense	274			—			—			—			274
Income from investment in subsidiaries	(133,336		)	—			(32		)	133,368			—
Total other (income) expenses	(95,421		)	(1,643		)	(81		)	133,368			36,223
Income (loss) before taxes	(366,581		)	208,324			64			(133,368		)	(291,561		)
Provision (benefit) for income taxes:
Current	159			—			—			—			159
Deferred	(177,197		)	75,020			—			—			(102,177		)
Total income taxes	(177,038		)	75,020			—			—			(102,018		)
Net income (loss)	$	(189,543	)	$	133,304		$	64		$	(133,368	)	$	(189,543	)
Comprehensive income (loss)	$	(104,166	)	$	133,304		$	64		$	(133,368	)	$	(104,166	)

F-46

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2016

(In thousands)



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net loss	$	(590,586	)	$	(286,172	)	$	(12,892	)	$	299,064		$	(590,586	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	67,059			153,020			—			—			220,079
Write-down of oil and gas properties	26,706			330,373			352			—			357,431
Accretion expense	232			39,997			—			—			40,229
Deferred income tax benefit	—			13,080			—			—			13,080
Settlement of asset retirement obligations	(85		)	(19,530		)	(899		)	—			(20,514		)
Non-cash stock compensation expense	8,443			—			—			—			8,443
Non-cash derivative expense	—			1,471			—			—			1,471
Non-cash interest expense	18,404			—			—			—			18,404
Non-cash reorganization items	8,332			—			—			—			8,332
Other non-cash expense	168			—			6,080			—			6,248
Change in current income taxes	20,088			—			—			—			20,088
Non-cash loss from investment in subsidiaries	292,618			—			6,446			(299,064		)	—
Change in intercompany receivables/payables	43,330			(42,449		)	(881		)	—			—
(Increase) decrease in accounts receivable	(7,490		)	6,078			—			—			(1,412		)
(Increase) decrease in other current assets	(3,526		)	—			33			—			(3,493		)
Increase (decrease) in accounts payable	4,313			(3,287		)	—			—			1,026
Increase (decrease) in other current liabilities	10,321			(424		)	—			—			9,897
Other	(9,178		)	(957		)	—			—			(10,135		)
Net cash (used in) provided by operating activities	(110,851		)	191,200			(1,761		)	—			78,588
Cash flows from investing activities:
Investment in oil and gas properties	(86,442		)	(151,158		)	(352		)	—			(237,952		)
Investment in fixed and other assets	(1,266		)	—			—			—			(1,266		)
Change in restricted funds	—			—			1,046			—			1,046
Investment in subsidiaries	—			—			715			(715		)	—
Net cash (used in) provided by investing activities	(87,708		)	(151,158		)	1,409			(715		)	(238,172		)
Cash flows from financing activities:
Proceeds from bank borrowings	477,000			—			—			—			477,000
Repayments of bank borrowings	(135,500		)	—			—			—			(135,500		)
Deferred financing costs	(900		)	—			—			—			(900		)
Repayments of building loan	(423		)	—			—			—			(423		)
Equity proceeds from parent	—			—			(715		)	715			—
Net payments for share-based compensation	(762		)	—			—			—			(762		)
Net cash used in financing activities	339,415			—			(715		)	715			339,415
Effect of exchange rate changes on cash	—			—			(9		)	—			(9		)
Net change in cash and cash equivalents	140,856			40,042			(1,076		)	—			179,822
Cash and cash equivalents, beginning of period	9,681			2			1,076			—			10,759
Cash and cash equivalents, end of period	$	150,537		$	40,044		$	—		$	—		$	190,581

F-47

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2015

(In thousands)



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net loss	$	(1,090,915	)	$	(184,124	)	$	(95,318	)	$	279,442		$	(1,090,915	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	123,724			157,964			—			—			281,688
Write-down of oil and gas properties	785,463			529,354			47,630			—			1,362,447
Accretion expense	365			25,623			—			—			25,988
Deferred income tax benefit	(114,418		)	(157,893		)	—			—			(272,311		)
Settlement of asset retirement obligations	(15		)	(72,367		)	—			—			(72,382		)
Non-cash stock compensation expense	12,324			—			—			—			12,324
Excess tax benefits	(1,586		)	—			—			—			(1,586		)
Non-cash derivative expense	—			16,440			—			—			16,440
Non-cash interest expense	17,788			—			—			—			17,788
Change in current income taxes	(37,377		)	—			—			—			(37,377		)
Non-cash loss from investment in subsidiaries	231,783			—			47,659			(279,442		)	—
Change in intercompany receivables/payables	9,744			(19,486		)	9,742			—			—
Decrease in accounts receivable	34,609			9,084			31			—			43,724
(Increase) decrease in other current assets	1,799			—			(32		)	—			1,767
(Increase) decrease in inventory	(1,394		)	2,698			—			—			1,304
Decrease in accounts payable	(7,471		)	(7,111		)	—			—			(14,582		)
Increase (decrease) in other current liabilities	(25,989		)	53			—			—			(25,936		)
Other	256			(1,163		)	—			—			(907		)
Net cash (used in) provided by operating activities	(61,310		)	299,072			9,712			—			247,474
Cash flows from investing activities:
Investment in oil and gas properties	(188,154		)	(323,359		)	(10,534		)	—			(522,047		)
Proceeds from sale of oil and gas properties, net of expenses	—			22,839			—			—			22,839
Investment in fixed and other assets	(1,549		)	—			—			—			(1,549		)
Change in restricted funds	177,647			—			1,820			—			179,467
Investment in subsidiaries	—			—			(9,714		)	9,714			—
Net cash used in investing activities	(12,056		)	(300,520		)	(18,428		)	9,714			(321,290		)
Cash flows from financing activities:
Proceeds from bank borrowings	5,000			—			—			—			5,000
Repayments of bank borrowings	(5,000		)	—			—			—			(5,000		)
Deferred financing costs	(68		)	—			—			—			(68		)
Proceeds from building loan	11,770			—			—			—			11,770
Excess tax benefits	1,586			—			—			—			1,586
Equity proceeds from parent	—			—			9,714			(9,714		)	—
Net payments for share-based compensation	(3,127		)	—			—			—			(3,127		)
Net cash provided by financing activities	10,161			—			9,714			(9,714		)	10,161
Effect of exchange rate changes on cash	—			—			(74		)	—			(74		)
Net change in cash and cash equivalents	(63,205		)	(1,448		)	924			—			(63,729		)
Cash and cash equivalents, beginning of period	72,886			1,450			152			—			74,488
Cash and cash equivalents, end of period	$	9,681		$	2		$	1,076		$	—		$	10,759

F-48

Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014

(In thousands)



	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(189,543	)	$	133,304		$	64		$	(133,368	)	$	(189,543	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	138,313			201,693			—			—			340,006
Write-down of oil and gas properties	351,192			—			—			—			351,192
Accretion expense	230			28,181			—			—			28,411
Deferred income tax (benefit) provision	(177,197		)	75,020			—			—			(102,177		)
Settlement of asset retirement obligations	(201		)	(56,208		)	—			—			(56,409		)
Non-cash stock compensation expense	11,325			—			—			—			11,325
Non-cash derivative income	—			(18,028		)	—			—			(18,028		)
Non-cash interest expense	16,661			—			—			—			16,661
Change in current income taxes	158			—			—			—			158
Non-cash income from investment in subsidiaries	(133,336		)	—			(32		)	133,368			—
Change in intercompany receivables/payables	114,056			(145,250		)	31,194			—			—
(Increase) decrease in accounts receivable	1,131			50,514			(34		)	—			51,611
Increase in other current assets	(6,238		)	—			(6		)	—			(6,244		)
(Increase) decrease in inventory	2,415			(2,415		)	—			—			—
Decrease in accounts payable	(662		)	(2,757		)	—			—			(3,419		)
Decrease in other current liabilities	(16,946		)	(2,206		)	—			—			(19,152		)
Other	(1,755		)	(1,496		)	—			—			(3,251		)
Net cash provided by operating activities	109,603			260,352			31,186			—			401,141
Cash flows from investing activities:
Investment in oil and gas properties	(338,731		)	(558,003		)	(30,513		)	—			(927,247		)
Proceeds from sale of oil and gas properties, net of expenses	28,103			214,811			—			—			242,914
Investment in fixed and other assets	(10,182		)	—			—			—			(10,182		)
Change in restricted funds	(177,647		)	—			(425		)	—			(178,072		)
Investment in subsidiaries	—			—			(31,696		)	31,696			—
Net cash used in investing activities	(498,457		)	(343,192		)	(62,634		)	31,696			(872,587		)
Cash flows from financing activities:
Proceeds from issuance of common stock	225,999			—			—			—			225,999
Deferred financing costs	(3,371		)	—			—			—			(3,371		)
Equity proceeds from parent	—			—			31,696			(31,696		)	—
Net payments for share-based compensation	(7,182		)	—			—			—			(7,182		)
Net cash provided by financing activities	215,446			—			31,696			(31,696		)	215,446
Effect of exchange rate changes on cash	—			—			(736		)	—			(736		)
Net change in cash and cash equivalents	(173,408		)	(82,840		)	(488		)	—			(256,736		)
Cash and cash equivalents, beginning of period	246,294			84,290			640			—			331,224
Cash and cash equivalents, end of period	$	72,886		$	1,450		$	152		$	—		$	74,488

F-49

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GLOSSARY OF CERTAIN INDUSTRY TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this Form 10-K. The revisions and additions to the definition section in Rule 4-10(a) of Regulation S-X contained in the SEC’s rule, "Modernization of Oil and Gas Reporting", are included. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the rule.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of gas.

Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Gross acreage or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Liquidity. The ability to obtain cash quickly either through the conversion of assets or the incurrence of liabilities.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of gas.

Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent. Determined using the ratio of six mcf of natural gas to one barrel of crude oil.

MMBtu. One million Btus.

MMcf. One million cubic feet of gas.

MMcfe. One million cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells expressed as whole numbers and fractions of whole numbers.

Primary term lease. An oil and gas property with no existing production, in which Stone has a specific time frame to establish production without losing the rights to explore the property.

Productive well. A well that is found to be mechanically capable of producing hydrocarbons in sufficient quantities that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction technology equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

G-1

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Proved oil and natural gas reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Reasonable certainty is defined as "much more likely to be achieved than not".

Proved undeveloped reserves ("PUDs"). Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Standardized measure of discounted future net cash flows. The standardized measure represents value-based information about an enterprise’s proved oil and natural gas reserves based on estimates of future cash flows, including income taxes, from production of proved reserves assuming continuation of certain economic and operating conditions. Future cash flows are based on a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

G-2

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EXHIBIT INDEX



Exhibit Number		Description
2.1		Second Amended Joint Prepackaged Plan of Reorganization of Stone Energy Corporation and its Debtor Affiliates, dated December 28, 2016 (incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed February 15, 2017 (File No. 001-12074)).
3.1		Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (File No.001-12074)).
3.2		Amended & Restated Bylaws of Stone Energy Corporation, dated December 19, 2013 (incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-12074)).
4.1		Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).
4.2		Senior Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).
4.3		First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).
4.4		Indenture related to the 1 3⁄4% Senior Convertible Notes due 2017, dated as of March 6, 2012, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A., as trustee (including form of 1 3⁄4% Senior Convertible Senior Note due 2017) (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).
4.5		Second Supplemental Indenture, dated as of November 8, 2012, to the Indenture, dated as of January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed November 8, 2012 (File No. 001-12074)).
4.6		Third Supplemental Indenture, dated as of November 26, 2013, to the Indenture, dated as of January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed November 27, 2013 (File No. 001-12074)).
4.7		First Supplemental Indenture and Guarantee, dated as of May 7, 2015, among SEO A LLC, SEO B LLC, Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A, as trustee (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-12074)).
4.8		Fourth Supplemental Indenture, dated as of May 7, 2015, among SEO A LLC, SEO B LLC, Stone Energy Corporation, Stone Energy Offshore, L.L.C. and The Bank of New York Mellon Trust Company, N.A, as trustee (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-12074)).
†10.1		Deferred Compensation and Disability Agreement between TSPC and E. J. Louviere dated July 16, 1981 (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
†10.2		Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015) (incorporated by reference to Exhibit 10.2 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 001-12074)).
†10.3		First Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015) (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed May 20, 2016 (File No. 001-12074)).
†10.4		Second Amendment to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (As Amended and Restated December 17, 2015) (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 (File No. 001-12074)).

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†10.5		Stone Energy Corporation Revised (2005) Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.6		Stone Energy Corporation Amended and Restated Revised Annual Incentive Compensation Plan, dated November 14, 2007 (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-12074)).
†10.7		Stone Energy Corporation 2016 Performance Incentive Compensation Plan (approved March 10, 2016) (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 (File No. 001-12074)).
†10.8		Stone Energy Corporation Deferred Compensation Plan (incorporated by reference to Exhibit 4.5 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.9		Adoption Agreement between Fidelity Management Trust Company and Stone Energy Corporation for the Stone Energy Corporation Deferred Compensation Plan dated December 1, 2004 (incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.10		Letter Agreement dated May 19, 2005 between Stone Energy Corporation and Kenneth H. Beer (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2005 (File No. 001-12074)).
†10.11		Letter Agreement dated December 2, 2008 between Stone Energy Corporation and David H. Welch (incorporated by reference to Exhibit 10.8 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 001-12074)).
†10.12		Amendment to Employment Agreement dated December 13, 2016 between Stone Energy Corporation and David H. Welch (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
†10.13		Letter Agreement dated August 10, 2016 between Stone Energy Corporation and Richard L. Toothman, Jr. (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (File No. 001-12074)).
†10.14		Stone Energy Corporation Executive Change of Control and Severance Plan (as amended and restated effective December 31, 2008) (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed April 8, 2009 (File No. 001-12074)).
†10.15		Executive Claims Settlement Agreement, dated December 13, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
†10.16		Stone Energy Corporation Executive Severance Plan, dated December 13, 2016 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
†10.17		Stone Energy Corporation Key Executive Incentive Plan, dated December 13, 2016 (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
†10.18		Stone Energy Corporation Employee Change of Control Severance Plan (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed December 12, 2007 (File No. 001-12074)).
10.19		Form of Indemnification Agreement between Stone Energy Corporation and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 27, 2009 (File No. 001-12074)).
10.20		Fourth Amended and Restated Credit Agreement among Stone Energy Corporation as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, and the financial institutions named therein, dated June 24, 2014 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed June 25, 2014 (File No. 001-12074)).
10.21		Amendment No. 1 to Credit Agreement, dated as of May 1, 2015, among Stone Energy Corporation as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, and the financial institutions party to the Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-12074)).
10.22		Amendment No. 3 to the Fourth Amended and Restated Credit Agreement among Stone Energy Corporation, certain of its subsidiaries, as guarantors, and the financial institutions party thereto, dated June 14, 2016 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed June 14, 2016 (File No. 001-12074)).

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10.23		Amendment No. 4 to the Fourth Amended and Restated Credit Agreement among Stone Energy Corporation, certain of its subsidiaries, as guarantors, and the financial institutions party thereto, dated December 9, 2016 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed December 9, 2016 (File No. 001-12074)).
10.24		Amended and Restated Security Agreement, dated as of August 28, 2008, among Stone Energy Corporation and the other Debtors parties hereto in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-12074)).
10.25		Amended and Restated Restructuring Support Agreement, dated December 14, 2016, by and among the Stone Parties and the Consenting Noteholders (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed December 14, 2016 (File No. 001-12074)).
10.26		Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and TH Exploration III, LLC as buyer, dated October 20, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed October 21, 2016 (File No. 001-12074)).
10.27		First Amendment to Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and TH Exploration III, LLC as buyer, dated December 9, 2016 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed December 9, 2016 (File No. 001-12074)).
10.28		Purchase and Sale Agreement by and between Stone Energy Corporation as seller, and EQT Production Company as buyer, and EQT Corporation as buyer parent, dated February 9, 2017 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed February 10, 2017 (File No. 001-12074)).
*21.1		Subsidiaries of the Registrant.
*23.1		Consent of Independent Registered Public Accounting Firm.
*23.2		Consent of Netherland, Sewell & Associates, Inc.
*31.1		Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2		Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1		Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
*99.1		Report of Netherland, Sewell & Associates, Inc.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Taxonomy Extension Schema Document
*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB		XBRL Taxonomy Extension Label Linkbase Document
*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

________________



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

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Stone Energy (SGY) 10-K2016 FY Annual report

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