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		Page No.
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	1012
Item 1B.	Unresolved Staff Comments	2328
Item 2.	Properties	2328
Item 3.	Legal Proceedings	2934
Item 4.	Mine Safety Disclosures	2935

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	3036
Item 6.	Selected Financial Data	3339
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3440
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	4659
Item 8.	Financial Statements and Supplementary Data	4760
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	4760
Item 9A.	Controls and Procedures	4760
Item 9B.	Other Information	5062

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	5062
Item 11.	Executive Compensation	5067
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	5095
Item 13.	Certain Relationships and Related Transactions, and Director Independence	5096
Item 14.	Principal Accountant Fees and Services	5097

PART IV

Item 15.	Exhibits and Financial Statement Schedules	5198
	Index to Financial Statements	F-1
	Glossary of Certain Industry Terms	G-1

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 910 of this document for an explanation of these types of statements. We use the terms “Stone,” “Stone Energy,” ~~“company,~~“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”~~"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, ~~2015,~~2016, our estimated proved oil and natural gas reserves were approximately 5753 MMBoe or ~~342~~321 Bcfe. ~~During 2015, approximately 95 MMBoe or 570 Bcfe~~In connection with our restructuring efforts, we entered into a purchase and sale agreement to sell all of our ~~estimated proved reserves were revised downward as a result~~Appalachia Properties (as defined in Reorganization and Chapter 11 Proceedings – Purchase and Sale Agreement below). We expect to close the sale of ~~lower oil, natural gas and natural gas liquids ("NGL") prices.~~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 ~~has~~ continued ~~into~~throughout 2015 and 2016. In response to that decline and the uncertainty regarding future commodity prices, we ~~have~~ adjusted our near-term strategy to focus on maintaining maximum liquidity, which ~~has~~ included reductions in ~~planned~~ capital expenditures in 2016 and the shut-in of our Mary field in Appalachia from September 2015 until late June 2016. ~~We plan~~In March 2016, we retained financial and legal advisors to ~~continuously evaluate~~assist the Company in analyzing and considering financial, transactional and strategic alternatives.

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 ~~operating activity~~our indebtedness and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in ~~light~~the agreements governing our indebtedness. As of ~~both actual~~December 31, 2016, we had total indebtedness of $1,427.8 million, including $300 million of 1¾% Senior Convertible Notes due in March 2017 (the "2017 Convertible Notes"), $775 million of 7½% Senior Notes due in 2022 (the "2022 Notes"), $341.5 million outstanding under our bank credit facility and $11.3 million outstanding under our 4.20% Building Loan (the "Building Loan"). Additionally, we had $35.2 million of accrued interest payable on our outstanding indebtedness.

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

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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 ~~changes~~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 Debtorsare ~~able~~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 ~~make~~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 ~~costs~~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 ~~operations,~~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 ~~make further~~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 ~~our cost structure~~the purchase price of up to $16 million in an amount equal to certain downward adjustments, as the prevailing bid.

On February 9, 2017, the Company entered into a purchase and ~~capital expenditure program as appropriate. See~~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. 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.

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 ~~99%~~66% of our estimated proved oil and natural gas reserves at December 31, ~~2015~~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 ~~90%~~56% of our estimated proved oil and natural gas reserves at December 31, ~~2015~~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 toin 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. ~~We have made~~

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~~two onshore, south Louisiana, deep gas discoveries and a GOM shelf deep gas discovery.~~ Our conventional shelf and deep gas properties accounted for approximately 9%10% of our estimated proved oil and natural gas reserves at December 31, ~~2015~~2016 on a volume equivalent basis.

Appalachia

The Marcellus shale provides us fairly predictable and repeatable results, as there is minimal exploration risk. We have assembled a team in Appalachia to execute the acreage acquisition, drilling and production of this resource play. Since 2006, we have secured leasehold interests in the Appalachia regions of Pennsylvania and West Virginia, and as of December 31, 2015, we held leasehold interests in approximately 89,000 net acres and have completed 136 wells. In addition to the Marcellus shale, we have development opportunities in the Utica shale on most of our acreage position. Other operators have drilled numerous Utica wells around our Appalachian acreage, and in late 2014, we successfully drilled our first Utica shale well in our Mary field. We believe much of our Mary, Heather and Buddy fields are prospective in the Utica shale.

At December 31, 2014, our Appalachian properties accounted for approximately 58% (526 Bcfe) of our estimated proved oil and natural gas reserves on a volume equivalent basis. However, during 2015, virtually all of our Appalachian reserves were removed from proved reserves due to the effect of reduced Appalachian reserve prices for natural gas of $1.52 per Mcf and NGLs of $11.19 per Bbl. In response to low commodity prices and high midstream costs in the area, we shut in our Mary field onfrom September 1, 2015 ~~curtailing approximately 100 MMcfe per day of production. Additionally, we~~until late June 2016 and suspended completion operations on 2325 drilled wells in Appalachia until ~~pricing~~commodity prices and margin improvements ~~can~~could be realized. ~~Our~~In late June 2016, ~~capital expenditure budget assumes only minimal activity~~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, which will entail lease maintenance expenditures~~Appalachia. See Reorganization and ~~satisfying obligations under our Appalachian rig commitment.~~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~~Company if successful. Given the uncertainty regarding future commodity prices, we have ~~allocated~~ only a minimal ~~portion of our 2016~~ capital ~~expenditure budget~~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 ~~53%~~68% and ~~13%~~10%, respectively, of our oil and natural gas revenue generated during the year ended December 31, ~~2015.~~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 ~~the Appalachia region~~ 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.

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Various aspects of our oil and natural gas operations are regulated by ~~administrative agencies of the states where we conduct operations and by~~ certain agencies of the federal government for our operations on federal leases. ~~All of the~~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 ~~states~~agencies can order the pooling or integration of tracts to facilitate exploration while ~~other states~~others rely on voluntary pooling of lands and leases. In addition, ~~state~~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”~~("BSEE") and the Bureau of Ocean Energy Management ~~(“BOEM”~~("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”~~"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”~~("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 ~~2015,~~2016, BSEE ~~released a proposed rule containing more stringent standards relating to~~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 ~~used in connection~~associated with ~~offshore~~ well ~~drilling operations. The proposed standards focus~~control operations, focusing on requirements for blowout preventers ~~along with~~("BOPs"), well design, well control casing, cementing, real-time ~~well~~ monitoring and subsea ~~containment requirements.~~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.

~~Also, in September 2015, the~~Additionally, on July 14, 2016, BOEM issued its “Draft Guidance” describing revised supplemental bonding procedures the agency plans to use to impose financial assurance obligations for decommissioning activities on the federal OCS. Once the Draft Guidance is finalized, the BOEM will issue these supplemental bonding changes in a ~~revised~~new Notice to Lessees ~~(“NTL”~~("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 ~~replacement~~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 ~~existing~~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, onor 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 ~~that was made effective on August 28, 2008. Among other things,~~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 ~~Draft Guidance proposes to eliminate~~suspension or cancellation of leases.

If fully implemented, the “waiver” exemption currently allowed by BOEM, whereby certain operators on the OCS projecting a relatively large net worth and meeting certain other criteria have the option of being exempted from posting bonds or other acceptable assurances for such operator’s decommissioning obligations. Currently, qualifying operators may self-insure to meet supplemental bonding requirements, but only so long as the cumulative decommissioning liability amount being self-insured by the operator is no more than 50% of the operator’s net worth. Under the Draft Guidance, this waiver option would be eliminated and operators would only be able to self-insure for an amount that is no more than 10% of their tangible net worth.

~~In 2016, we expect that we will not be able to qualify for a supplemental bonding waiver under the existing~~new NTL as suppressed oil and natural gas prices have negatively affected our net worth. If we cannot qualify for a waiver, we will have to obtain surety bonds or other forms of financial assurance, the costs of which could be significant. Moreover, BOEM’s Draft Guidance 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, ~~exceed~~challenge the surety bond market’s ~~current~~ 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”~~2005"). Among other matters, EPAct 2005 amends the Natural Gas Act (the ~~“NGA”~~"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”~~"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

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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~~"in connection ~~with”~~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”~~"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.

In 2007, the FERC issued Order No. 704 requiring that any market participant, including a producer such as Stone Energy, that engages in sales for resale or purchases for resale of natural gas that equal or exceed 2.2 million MMBtus during a calendar year to annually report such sales or purchases to the FERC, beginning on May 1, 2009. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation. The monitoring and reporting required by these rules have increased our administrative costs. 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. As a result of initiatives such as FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers,industry, including ~~producers, from effectively competing with~~requiring interstate pipelines ~~for sales~~ to ~~local distribution companies and large industrial and commercial customers. The most significant provisions of FERC Order No. 636 require that interstate pipelines~~ provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of FERC Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Similarly,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”~~"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 ~~NGLs~~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

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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 ~~onshore and~~ offshore oil and gas properties in the United States, we are subject to stringent federal, state and local laws and regulations relating to ~~environmental~~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”~~"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, ~~from time to time various~~in December 2016, the EPA and environmental groups ~~have challenged the EPA's exemption of~~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”~~"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 ~~for~~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”~~"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

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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”~~"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 ~~(the “CAA”~~("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. ~~Recently,~~Recent regulation of emissions of greenhouse gases has focused on fugitive methane emissions. For example, in ~~December 2015,~~June 2016, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. Also, in August 2015, the EPA announced proposed rules that would 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 ~~proposed~~ 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 Bureau of Land Management (“BLM”) also proposed new rules in January 2016 which seek to limit methane emissions from new and existing oil and gas operations on federal lands. The proposal would limit venting and flaring of gas, impose leak detection and repair requirements on wellsite equipment and compressors, and also require the installation of new controls on pneumatic pumps, and other activities at the wellsite such as downhole well maintenance and liquids unloading and drilling workovers and completions to reduce leaks of methane. Compliance with these proposed rules will require enhanced record-keeping practices, and may require the purchase of new equipment such as optical gas imaging instruments to detect leaks, and increase the frequency of maintenance and repair activities to address emissions leakage. The rules may also require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

In addition, while the United States Congress has ~~from time to time considered adopting legislation~~not taken any legislative action to reduce emissions of greenhouse gases, ~~and~~ many states have ~~already taken legal measures to reduce emissions of greenhouse gases primarily through regional~~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. ~~Any such legislation or regulatory programs~~Substantial limitations on greenhouse gas emissions could also ~~increase the cost of consuming, and thereby reduce~~adversely affect demand for the oil and natural gas we ~~produce.~~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.

~~Hydraulic fracturing.~~ Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing in our onshore operations. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control Program and issued permitting guidance for such activities in February 2014. In addition, in May 2014, the EPA proposed rules under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued. Moreover, the EPA proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

Also, in June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water

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~~resources in~~At this time, we have not yet developed a comprehensive plan to address the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. A numberlegal, economic, social, or physical impacts of ~~other federal agencies, including the U.S. Department of Energy, the U.S. Department of the Interior and the White House Council~~climate change on Environmental Quality, are studying various aspects of hydraulic fracturing. These studies, depending on their findings, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

In addition, from time to time legislation has been introduced before the United States Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process; although no actions have been taken to date. Some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, hydraulic fracturing fluid disclosure, air emission limitations, and well construction requirements on hydraulic fracturingour operations. For example, Pennsylvania, Texas, Colorado and Wyoming have each adopted a variety of well construction, set back and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. Also, in January 2016, Pennsylvania announced new rules that will require the Pennsylvania Department of Environmental Protection (“PADEP”) to develop a new general permit for oil and gas exploration, development, and production facilities, requiring best available technology for equipment and processes, enhanced record-keeping, and quarterly monitoring inspections for the control of methane emissions. The PADEP also intends to issue similar methane rules for existing sources. These rules have the potential to increase our compliance costs. Moreover, some states and local jurisdictions have taken steps to limit hydraulic fracturing within their borders or ban the practice altogether. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could impact the timing of production and may also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Water discharges. The federal Water Pollution Control Act (the ~~“Clean~~"Clean Water ~~Act”~~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 ~~or dredge and fill material~~ into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or ~~in some instances, the U.S. Army Corps of Engineers, or~~ an analogous state agency. In September 2015, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rules expand the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. 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.~~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”~~("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. In addition, the EPA has adopted new rules under the CAA that require the reduction of volatile organic compound ("VOC") emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. More recently, in August 2015, the EPA announced proposed rules that would 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 proposed 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, the rule package would extend existing VOC standards under the EPA’s Subpart OOOO of the New Source Performance Standards to include previously unregulated equipment within the oil and natural gas source category. These rules may require a number of modifications to our operations, including the

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~~installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.~~

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 ~~Endangered Species Act (“ESA”) provides~~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 ~~endangered~~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 ~~threatened species. Pursuant to~~fauna that have been officially classified as "threatened" or "endangered" are protected by the ~~ESA, if~~Endangered Species Act ("ESA"). This law prohibits any activities that could “take” a ~~species is listed as threatened~~protected plant or ~~endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.~~animal or reduce or degrade its habitat area. We conduct operations on ~~natural gas and oil~~ 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. ~~The U.S.~~

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 ~~Service (the “USFWS”)~~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 ~~designate critical habitat and suitable habitat areas that it believes are necessary for survival~~require the acquisition of a ~~threatened~~permit or ~~endangered species. A critical habitat~~other authorization before construction or ~~suitable habitat designation could result in further material restrictions to federal land use~~drilling commences and may ~~materially delay~~limit or prohibit ~~access to~~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 ~~natural gas and oil development. Moreover, as a result of a settlement, the USFWS is~~pollution resulting from our operations. The permits required to make a determination as to whether more than 250 species as endangered or threatened should be listed under the ESA by no later than completion of the agency’s 2017 fiscal year. For example, in April 2015, the USFWS listed the northern long-eared bat, whose habitat includes the areas in which we operate, as a threatened species under the ESA. The designation of previously unprotected species as threatened or endangered in areas where underlying propertyfor our various operations are ~~conducted could cause us~~subject to ~~incur increased costs arising from species protection measures or could result in limitations on our exploration~~revocation, modification and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.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 ~~22, 2016,~~23, 2017, we had ~~310~~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”~~"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”~~("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 ~~16, 2015.~~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.

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Forward-Looking Statements

The information in this Form 10-K includes ~~“forward-looking statements”~~"forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the ~~“Securities Act”~~"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:

~~any expected results or benefits associated with our acquisitions;~~

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;

~~consequences of a catastrophic event like the Deepwater Horizon oil spill;~~

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 ~~restructure our debt,~~or raise additional ~~capital or seek bankruptcy protection;~~capital;

~~our ability to continue to borrow under our credit facility;~~

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;

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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;~~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, including changes affecting our offshore and Appalachian operations;~~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 ~~and~~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 ~~has been shut-in since~~from September 1, 2015 ~~due to low prices for natural gas and NGLs, and high midstream costs.~~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, ~~2015,~~2016, the West Texas Intermediate ~~(“WTI”~~("WTI") crude oil price per Bbl ranged from a low of ~~$34.73~~$26.21 to a high of $110.53, and the New York Mercantile Exchange ~~(“NYMEX”~~("NYMEX") natural gas price per MMBtu ranged from a low of ~~$1.76~~$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;

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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.

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. Increases in financial assurance requirements could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

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.

In addition, in September 2015, the BOEM issued its Draft Guidance describing revised supplemental bonding procedures the agency plans to use to impose financial assurance obligations for decommissioning activities on the federal OCS. Once the Draft Guidance is finalized, the BOEM will issue these supplemental bonding changes in a revised NTL in replacement of an existing NTL on supplemental bonding that was made effective on August 28, 2008. Among other things, the Draft Guidance proposes to eliminate the “waiver” exemption currently allowed by BOEM, whereby certain operators on the OCS projecting a relatively large net worth and meeting certain other criteria have the option of being exempted from posting bonds or other acceptable assurances for such operator’s decommissioning obligations. Currently, qualifying operators may self-insure to meet supplemental bonding requirements, but only so long as the cumulative decommissioning liability amount being self-insured by the operator is no more than 50% of the operator’s net worth. Under the Draft Guidance, this waiver option would be eliminated and operators would only be able to self-insure for an amount that is no more than 10% of their tangible net worth.

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In 2016, we expect that we will not be able to qualify for a supplemental bonding waiver under the existing NTL as suppressed oil and natural gas prices have negatively affected our net worth. If we cannot qualify for a waiver, we will have to obtain surety bonds or other forms of financial assurance, the costs of which could be significant. Moreover, BOEM’s Draft Guidance 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, exceed the surety bond market’s current 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 may have about the priority of their lien on the operator's collateral. All of these factors may make it more difficult 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.

~~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. The majority of our existing operations are 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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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, 2015, approximately 27% 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.

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 expenditures program. In addition, if our borrowing base under our bank credit facility is redetermined to a lower amount, this could adversely affect our ability to fund our planned capital expenditures. 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 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 in the fourth quarter of 2014 and throughout 2015. Our stock price has decreased from $16.60 per share on January 1, 2015 to $1.85 per share on February 22, 2016, and could decline further. The current trading price of our common stock, or any further declines thereof, may impede our ability to raise capital through the issuance of additional shares of our common stock.

The closing market price of our common stock has recently declined significantly. If the average closing price of our common stock declines to less than $1.00 over 30 consecutive trading days, our common stock could be delisted from the New York Stock Exchange (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. A renewed or continued decline in the closing price of our common stock on the NYSE could result in a breach of these requirements. Although we would have an opportunity to take action to cure such a breach, if we did not succeed, the NYSE could commence suspension or delisting procedures in respect of our common stock. In addition, 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 falls below $0.16 per share. In this event, we would not have an opportunity to cure the stock price 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.

~~Our estimates of future asset retirement obligations may vary significantly from period to period.~~

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. The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which

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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.

~~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 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 may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

As of December 31, 2015, we had total indebtedness of $1,087 million and, as of February 22, 2016, we had total indebtedness of $1,137 million. Based on our current debt balance, we expect to have interest payments due during 2016, totaling approximately $67 million. In addition, our 2017 Convertible Notes (as defined herein) mature in March 2017, and most of our other outstanding indebtedness will mature within the next seven years. Our ability to make scheduled payments on, or to refinance, our debt obligations will depend on our financial and operating performance, which is subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. 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. We cannot assure you that our business will generate sufficient cash flows from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to service our indebtedness or repay our indebtedness as it becomes due or to fund our other liquidity needs. In addition, there can be no assurance that we will have the ability to borrow or otherwise raise the amounts necessary to repay or refinance our indebtedness as it matures. If we are unable to generate sufficient cash flow to service our debt or meet our debt obligations as they become due, we may be required to restructure or refinance all or a portion of our debt, obtain additional financing, sell some of our assets or operations or reduce or delay capital expenditures, including development and exploration efforts and acquisitions.

We may be unable to restructure or refinance our debt, obtain additional financing or capital or sell assets on satisfactory terms, if at all. If we cannot make scheduled payments on our debt, we will be in default under the terms of the agreements governing our debt and, as a result, our debt holders could declare all outstanding principal and interest to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. The lenders under our revolving credit facility could also terminate their commitments to lend us money and foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation.

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:

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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 ~~in the quarter ended December 31, 2015 and further in the current quarter.~~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. As of December 31, 2015, we were in compliance with all of our financial covenants under our bank credit facility and the indentures governing our outstanding notes. However, given the lower commodity prices and our reduced hedged position in 2016, we anticipate that we could exceed the Consolidated Funded Debt to consolidated EBITDA financial covenant of 3.75 to 1 set forth in our bank credit facility at the end of the first quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. We are currently in discussions with our banks regarding an amendment to our bank credit facility. If we are unable to reach an agreement with our banks or find acceptable alternative financing, it may lead to an event of default under our bank credit facility. If following an event of default, the banks were to accelerate repayment under the bank credit facility, it may result in an event of default and an acceleration under our other debt instruments.

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. ~~Our borrowing base is scheduled to be redetermined by May 2016.~~ 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 expect our borrowing base to be decreased by May 2016, but we do not expect a borrowing base deficiency at such time.~~

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 are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, assets sales and a prepackaged filingfiled for bankruptcy under Chapter 11 of the U.S. Bankruptcy ~~Code. Seeking Bankruptcy Court protection~~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.

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~~operations.

BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and ~~liquidity. So long as~~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 ~~proceeding related~~supplemental bonding waiver under the financial criteria specified in BOEM’s guidance to lessees at that time. In late March 2016, we proposed a ~~Chapter 11 proceeding continues,~~tailored plan to BOEM for financial assurances relating to our ~~senior management would be required to spend a significant amount~~abandonment obligations, which provides for posting some incremental financial assurances in favor of ~~time and effort dealing~~BOEM. On May 13, 2016, we received notice letters from BOEM rescinding its demand for supplemental bonding with the ~~reorganization instead~~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 ~~focusing~~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 ~~business operations. Bankruptcy Court protection also might make it more difficult~~tailored plan to ~~retain management and other key personnel necessary to~~reflect the success and growth of our business. In addition, the longer a proceeding related to a Chapter 11 proceeding continues, the more likely it is that our customers and suppliers would lose confidence in our ability to reorganize our businesses successfully and would seek to establish alternative commercial relationships.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, weit 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 ~~significant amount~~large number of ~~secured indebtedness that is senior~~operators on the OCS, which will in turn force these operators to ~~our unsecured indebtedness~~seek additional surety bonds and ~~a significant amount of total indebtedness that is senior to our existing common stock in our capital structure. As~~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 ~~we believe that seeking Bankruptcy Court protection under a Chapter 11 proceeding~~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.

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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 ~~and place equity holders at significant risk of losing~~or all of ~~their interests~~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 ~~company.~~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.

~~Approximately 56%~~Following the sale of the Appalachia Properties, our production ~~during 2015 was~~will be exclusively associated with our properties in the GOM ~~deep water,~~and the U.S. Gulf ~~Coast deep gas and GOM conventional shelf properties.~~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.

~~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~~ In accordance with industry practice, we maintain insurance against some, but 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 113,313 gross acres (54,686 net) that could potentially expire during fiscal year 2016. 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~~all, of these ~~factors are beyond our control, including drilling results, oil~~risks 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.losses.

We ~~may~~are 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.

~~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.

~~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

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reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a trailing 12-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 and throughout 2015. We recorded a non-cash ceiling test write-down of approximately $351 million for the year ended December 31, 2014 and approximately $1,362 million for the year ended December 31, 2015. 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.

~~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.

~~Part of our strategy includes drilling in new or emerging plays. As a result, our drilling in these areas is subject to greater risk and uncertainty.~~

We have made initial investments in acreage in untested regions. These activities are more uncertain than drilling in areas that are developed and have established production. Because emerging plays and new formations have limited or no production history, we are less able to use past drilling results to help predict future results. The lack of historical information may result in us not being able to fully execute our expected drilling programs in these areas or the return on investment in these areas may turn out not to be as attractive as anticipated. We cannot assure you that our future drilling activities in these emerging plays will be successful, or if successful, will achieve the resource potential levels that we currently anticipate based on the drilling activities that have been completed or will achieve the anticipated economic returns based on our current cost models.

~~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 canceled 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;~~

~~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

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~~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 have begun to 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.

~~We may not be~~ 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 ~~$1 billion~~$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, including $105 million of self-insurance.~~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.

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~~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~~Lower oil and natural gas prices and other factors have resulted, and in the future ~~targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those~~may result, in ceiling test write-downs and other impairments of our ~~purchasers, could have a material adverse effect on~~asset carrying values.

We use the full cost method of accounting for our ~~financial condition and operations.~~

~~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~~operations. Accordingly, we capitalize the costs to acquire, explore for 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 ordevelop oil and gas properties. ~~For example, new leases acquired~~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 ~~the BOEM are acquired through~~proved reserves (based on a ~~“sealed bid” process~~trailing twelve-month average, hedge-adjusted commodity price and ~~are generally awarded~~excluding cash flows related to estimated abandonment costs), 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 periodsnet capitalized costs 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 productiveproved 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 ~~exploratory prospects than~~gas properties exceed the estimated discounted future net cash flows from proved reserves, we are ~~able or willing~~required to ~~pay. Further,~~write down the value of our ~~competitors may be able~~oil and gas properties to ~~expend greater resources on~~ the ~~existing~~value of the estimated discounted future net cash flows. A write-down of oil and ~~changing technologies~~gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we ~~believe~~ will ~~impact attaining success~~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 ~~industry. If we are unable~~global economic markets and other factors could cause us to ~~compete successfully in these areas~~record additional write-downs of our oil and natural gas properties and other assets in the future ~~our~~and incur additional charges against future ~~revenues and growth may be diminished or restricted.~~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 ~~wetlands,~~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.

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.

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.

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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.

Our actual production could differ materially from our forecasts.

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.

Our industry experiences numerous operating risks.

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.

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.

There are uncertainties in successfully integrating our acquisitions.

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.~~us and our operations.

~~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

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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.~~

At December 31, 2015, two counterparties accounted for approximately 86% of our contracted volumes. 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.

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.

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

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.

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.

~~Future legislation may result in the elimination of certain~~Certain U.S. federal income tax deductions currently available with respect to ~~oil and~~ natural gas and oil exploration and ~~development. Additionally,~~development may be eliminated as a result of future ~~federal and state~~legislation.

In past years, legislation ~~may impose new or increased taxes or fees on oil and natural gas extraction.~~

~~Potential legislation,~~has been proposed that would, if enacted into law, ~~could~~ make significant changes to U.S. ~~federal and state income~~ tax laws, including ~~the elimination of~~to certain key U.S. federal income tax ~~incentives~~provisions currently available to oil and gas ~~exploration and production~~ companies. ~~These~~Such legislative changes ~~include,~~have included, but ~~are~~ not been limited to, (i) the repeal of the percentage depletion allowance for oil and ~~natural~~ gas ~~properties;~~properties, (ii) the elimination of current deductions for intangible drilling and development ~~costs;~~costs, (iii) the elimination of the deduction for certain ~~U.S.~~domestic production ~~activities;~~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

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could ~~become effective.~~take effect. The passage of ~~this~~any legislation as a result of these proposals or any ~~other~~ similar changes in U.S. federal ~~and state~~ income tax laws could eliminate or postpone certain tax deductions that currently are ~~currently~~ available with respect to oil and ~~natural~~ gas ~~exploration and~~ development, or increase costs, and any such ~~change~~changes could ~~negatively impact~~have an adverse effect on the ~~value~~Company’s financial position, results of ~~an investment in our common stock. Additionally, legislation could be enacted that increases the taxes states impose on oil~~operations and natural gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals, could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.cash flows.

Climate change legislation or regulations restricting emissions of ~~“greenhouse gases”~~"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”~~"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 ~~proposed~~ 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 BLM also proposed new rules in January 2016 which seek to limit methane emissions from new and existing oil and gas operations on federal lands. The proposal would limit venting and flaring of gas, impose leak detection and repair requirements on wellsite equipment and compressors, and also require the installation of new controls on pneumatic pumps, and other activities at the wellsite such as downhole well maintenance and liquids unloading and drilling workovers and completions to reduce leaks of methane. Compliance with these proposed rules will require enhanced record-keeping practices, and may require the purchase of new equipment such as optical gas imaging instruments to detect leaks, and increase the frequency of maintenance and repair activities to address emissions leakage. The rules may also require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

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

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”~~"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 ~~October 2011,~~one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued ~~regulations to set~~on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in ~~the major energy markets~~various commodities (including oil and gas) and for swaps that are their economic equivalents. ~~The initial~~Under the proposed rules on position limits, ~~rule was vacated by the United States District Court for the District~~certain types of ~~Colombia in September 2012. However, in November 2013, the CFTC proposed new rules that would place~~hedging transactions are exempt from these limits on the size of positions ~~in certain core futures and equivalent swap contracts for, or linked to, certain physical commodities, subject to exceptions~~that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain ~~bona~~enumerated "bona fide ~~hedging transactions.~~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.

~~Federal~~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 ~~state legislation~~natural gas, we periodically enter into oil and ~~regulatory initiatives relating~~natural gas price hedging arrangements with respect to ~~hydraulic fracturing could cause~~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 ~~incur increased costs~~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 ~~experience additional operating restrictions~~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 ~~delays.~~

~~Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly~~ natural gas ~~from tight formations. The process involves the injection of water, sand and chemicals under pressure~~prices; or

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

Currently, all of our outstanding commodity derivative instruments are with certain lenders or affiliates of the ~~surrounding rock~~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 stimulate production. We routinely use hydraulic fracturing in our onshore operations. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA Underground Injection Control Program and issued permitting guidance for such activities in February 2014. In addition, in May 2014, the EPA proposed rules under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued. Moreover, the EPA proposed in April 2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.

~~Also, in June 2015, the EPA released its draft report~~will depend on the ~~potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water~~

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~~resources in~~arrangements we negotiate with the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. The draft report is expected to be finalized after a public comment period and a formal review by the EPA’s Science Advisory Board. A number of other federal agencies, including the U.S. Department of Energy, the U.S. Department of the Interiorcounterparty and the White House Council on Environmental Quality, are studying various aspects of hydraulic fracturing. These studies, depending on their findings, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

In addition, from time to time legislation has been introduced before the United States Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process although no actions have been taken to date. Some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, hydraulic fracturing fluid disclosure, air emission limitations, and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Texas, Colorado and Wyoming have each adopted a variety of well construction, set back and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. Also, in January 2016, Pennsylvania announced new rules that will require the PADEP to develop a new general permit for oil and gas exploration, development, and production facilities, requiring best available technology for equipment and processes, enhanced record-keeping, and quarterly monitoring inspections for the control of methane emissions. The PADEP also intends to issue similar methane rules for existing sources. These rules have the potential to increase our compliance costs. Moreover, some states and local jurisdictions have taken steps to limit hydraulic fracturing within their borders or ban the practice altogether. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could impact the timing of production and may also reduce the amountvolatility of oil and natural gas ~~that we are ultimately able to produce from our reserves.~~prices and market conditions.

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

The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist ~~acts. The potential for such security threats has~~organizations. These developments have subjected our operations to increased ~~risks that~~risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our ~~business. In particular, the implementation of various procedures~~financial condition 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 the 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.operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

As of ~~February 22,~~December 31, 2016, our property portfolio consisted of ~~nine~~eight active properties and ~~103~~68 primary term leases in the GOM Basin, ~~(onshore and offshore),~~ three active properties in the Appalachia region and inactive undeveloped acreage in the ~~Appalachia and the~~ Rocky Mountain ~~regions.~~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 ~~94%~~93% of our year-end ~~2015~~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

~~Table of Contents~~

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, ~~2015~~2016 were independently prepared by Netherland, Sewell & Associates, Inc. ~~(“NSAI”~~("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 ~~99%~~66% of which are located in the GOM and 1%34% in the ~~Appalachian~~Appalachia region) as of December 31, ~~2015.~~2016. The ~~2015~~2016 average ~~12-month~~twelve-month oil and natural gas prices net of differentials were ~~$51.16~~$40.15 per Bbl of oil, ~~$16.40~~$9.46 per Bbl of NGLs and ~~$2.19~~$1.71 per Mcf of natural gas. During 2015, approximately 570 Bcfe of our estimated proved reserves were revised downward as a result of lower oil, natural gas and NGL prices, offset by approximately 42 Bcfe of positive well performance revisions.

									Summary of Oil, Natural Gas and NGL Reserves as of
December 31, 2015
December 31, 2016					December 31, 2016
	Oil (MBbls)	NGLs (MBbls)	Natural Gas (MMcf)	Oil, Natural Gas and NGLs (MMcfe)	Oil (MBbls)	NGLs (MBbls)	Natural Gas (MMcf)	Oil, Natural Gas and NGLs (MMcfe)
Reserves Category:
PROVED
Developed	21,734	4,784	90,262	249,366	18,269	9,255	90,741	255,884
Undeveloped	8,542	1,674	31,596	92,894	5,011	1,374	26,579	64,889
TOTAL PROVED	30,276	6,458	121,858	342,260	23,280	10,629	117,320	320,773

At December 31, ~~2015,~~2016, we reported estimated proved undeveloped reserves ~~(“PUDs”~~("PUDs") of ~~92.9~~64.9 Bcfe, which accounted for ~~27%~~20% of our total estimated proved oil and natural gas reserves. This figure ties to a projected ~~two~~four new wells ~~(27.0~~(60.2 Bcfe) and ~~six~~one sidetrack ~~wells~~well from an existing ~~wellbores (65.9~~wellbore (4.7 Bcfe). ~~We expect two or three of the sidetrack wells to be drilled in 2016, while the~~The timetable for drilling ~~of the remaining~~this sidetrack ~~wells~~well is totally dependent on the life of the currently producing ~~zones.~~zone. After the current ~~zones have~~zone has been depleted, we would utilize the existing wellbore to sidetrack to the PUD objective. Regarding the remaining ~~two~~four PUD locations, we project ~~one well~~three wells to be drilled in ~~2016 (16.8~~2017 (52.1 Bcfe) and one well in 2018 ~~(10.2~~(8.1 Bcfe). ~~Neither~~None of these ~~two~~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 ~~2015.~~2016.

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	Oil, Natural Gas and NGLs (MMcfe)		Future Development Costs (in thousands)			Oil, Natural Gas and NGLs (MMcfe)		Future Development Costs (in thousands)
PUDs beginning of year	445,006		$	895,289		92,894		$	181,954
Revisions of previous estimates	(352,112	)	(713,335		)	(11,051	)	(15,216		)
Conversions to proved developed reserves	—		—			(16,954	)	(37,766		)
Additional PUDs added	—		—			—		—
PUDs end of year	92,894		$	181,954		64,889		$	128,972

During ~~2015,~~2016, we ~~recognized downward revisions of 352~~invested approximately $37.8 million to convert 17.0 Bcfe of ~~previously booked~~ PUDs ~~due primarily~~ to proved developed reserves in the ~~effects of lower commodity prices.~~GOM. As of December 31, ~~2015,~~2016, we had no PUDs in the Appalachia region.

The following represents additional information on our significant properties:

December 31, 2015

December 31, 2016

2015

Estimated

2016

Estimated

Field Name

Location

Production

(MMcfe)

Proved Reserves

(MMcfe)

Nature of

Interest

Location

Production

(MMcfe)

Proved Reserves

(MMcfe)

Nature of

Interest

Pompano (1)

GOM Deep Water

21,799

264,212

Working

GOM Deep Water

32,629

142,302

Working

Mary (2)

Appalachia

29,050

—

Working

Appalachia

20,850

101,227

Working

Mississippi Canyon Block 109

GOM Deep Water

6,684

43,004

Working

GOM Deep Water

6,386

37,641

Working

Bayou Hebert

Gulf Coast Deep Gas

5,489

18,922

Working

Gulf Coast Deep Gas

3,916

14,064

Working

Main Pass Block 288

GOM Shelf

3,110

10,810

Working

GOM Shelf

3,554

10,533

Working

Heather

Appalachia

9,052

1,595

Working

Ship Shoal Block 113

GOM Shelf

6,764

1,198

Working

GOM Shelf

4,668

6,821

Working

Heather (2)

Appalachia

7,169

5,931

Working



*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.~~
#Name	~~Not considered to be “filed” for the purposes of Section 18~~	Age	Position
David H. Welch		68	Chairman of the ~~Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.~~Board, President and Chief Executive Officer
†Kenneth H. Beer	~~Identifies management contracts~~	59	Executive Vice President and ~~compensatory plans or arrangements.~~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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~~SIGNATURES~~

~~Pursuant~~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 ~~13 or 15(d)~~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 ~~Securities Exchange Act~~Board and its committees, which include Corporate Governance Guidelines, a Code of ~~1934,~~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 ~~registrant~~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 ~~duly caused this report~~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 ~~signed~~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 ~~its behalf by~~ the ~~undersigned, thereunto duly authorized.~~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.



		~~STONE ENERGY CORPORATION~~	Audit Committee,

~~Date:~~	~~February 26, 2016~~		~~By:~~ ~~/s/ David H. Welch~~	Kay G. Priestly - Chairman
			Peter D. Kinnear
			David ~~H. Welch~~T. Lawrence
			~~President,~~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 ~~Chairman~~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 ~~Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf~~assistance of the ~~registrant~~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 ~~capacities~~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 ~~dates indicated.~~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.



~~Signature~~	~~Title~~	~~Date~~
~~/s/ David H. Welch~~	~~President, Chief Executive Officer~~ ~~and Chairman of the Board~~ ~~(principal executive officer)~~	~~February 26, 2016~~
~~David H. Welch~~ Compensation Committee,		~~February 26, 2016~~

~~/s/ Kenneth H. Beer~~	~~Executive Vice President and~~ ~~Chief Financial Officer~~ ~~(principal financial officer)~~	~~February 26, 2016~~
~~Kenneth H. Beer~~George R. Christmas - Chairman		~~February 26, 2016~~

~~/s/ Karl D. Meche~~	~~Director of Accounting and Treasurer~~ ~~(principal accounting officer)~~	~~February 26, 2016~~
~~Karl D. Meche~~		~~February 26, 2016~~

~~/s/ George R. Christmas~~	~~Director~~	~~February 26, 2016~~
~~George R. Christmas~~	~~Director~~	~~February 26, 2016~~

~~/s/ B.J. Duplantis~~	~~Director~~	~~February 26, 2016~~
~~B.J.~~B. J. Duplantis	~~Director~~	~~February 26, 2016~~

~~/s/ Peter D. Kinnear~~	~~Director~~	~~February 26, 2016~~
Peter D. Kinnear	~~Director~~	~~February 26, 2016~~

~~/s/ David T. Lawrence~~	~~Director~~	~~February 26, 2016~~
~~David T. Lawrence~~	~~Director~~	~~February 26, 2016~~

~~/s/ Robert S. Murley~~	~~Director~~	~~February 26, 2016~~
Robert S. Murley	~~Director~~	~~February 26, 2016~~

~~/s/ Richard A. Pattarozzi~~	~~Director~~	~~February 26, 2016~~
~~Richard A. Pattarozzi~~	~~Director~~	~~February 26, 2016~~

~~/s/ Donald E. Powell~~	~~Director~~	~~February 26, 2016~~
~~Donald E. Powell~~	~~Director~~	~~February 26, 2016~~

~~/s/ Kay G. Priestly~~	~~Director~~	~~February 26, 2016~~
~~Kay G. Priestly~~	~~Director~~	~~February 26, 2016~~

~~/s/ Phyllis M. Taylor~~	~~Director~~	~~February 26, 2016~~
Phyllis M. Taylor	~~Director~~

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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~~INDEX TO FINANCIAL STATEMENTS~~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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~~Report of Independent Registered Public Accounting Firm~~	~~F-2~~
Individual
~~Consolidated Balance Sheet as December 31, 2015 and 2014~~	~~F-3~~ Multiple of Annual Retainer(1)
Nonemployee Director		5x annual retainer


~~Consolidated Statement~~(1)	In effect on January 1 of ~~Operations~~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 ~~years~~year ended December 31, ~~2015, 2014~~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 ~~2013~~(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.

~~F-4~~

(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.


~~Consolidated Statement~~(4)	In April 2016, Mr. Lawrence was named Special Liaison of ~~Comprehensive Income (Loss)~~the independent directors to work together with the management of the Company to help with assessing strategic alternatives and restructuring alternatives for the ~~years ended December 31, 2015, 2014 and 2013~~	~~F-5~~

~~Consolidated Statement~~Company. This represents the amount of ~~Cash Flows for the years ended December 31, 2015, 2014 and 2013~~	~~F-6~~

~~Consolidated Statement of Changes in Stockholders' Equity for the years ended December 31, 2015, 2014 and 2013~~	~~F-7~~

~~Notes~~compensation that Mr. Lawrence received with respect to ~~Consolidated Financial Statements~~	~~F-8~~ such services provided.

~~F-1~~94

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~~REPORT~~ITEM 12. SECURITY OWNERSHIP OF ~~INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM~~CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Directors, Management and Certain Beneficial Holders

The ~~Stockholders~~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 ~~Directors~~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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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, ~~2015~~2016 and ~~2014,~~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.

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.

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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.

Section 16(a) Beneficial Ownership Reporting Compliance

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 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

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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



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

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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

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Say-on-Pay Advisory Votes

Our Compensation Philosophy



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.

•

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

Base Salary (fixed pay)

Incentive Compensation (variable pay), which includes:


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



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

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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

Alignment of Pay and Performance

Peer Group for Assessing Pay and Performance

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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.

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.

ECI 2016 Survey Data for Assessing Pay and Performance

Role of Compensation Committee and Management

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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.

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.

Role of the Compensation Consultant

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



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

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		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



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

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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

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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

Long-Term Incentive Compensation

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.

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Stock Ownership and Retention Guidelines and Prohibition on Hedging



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.

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

Other Program Components

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Perquisites and Other Benefits

401(k) Plan

Deferred Compensation Plan

Severance Plan and Change of Control Benefits

2017 Compensation Arrangements

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

Stone Energy Corporation Key Executive Incentive Plan (KEIP)

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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

Executive Severance Plan and Employment Agreements

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Non-Qualified Stone Energy Corporation Deferred Compensation Plan

Stone Energy Corporation 2017 Long-Term Incentive Plan

Tax and Accounting Considerations

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

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EXECUTIVE COMPENSATION TABLES

Summary Compensation Table



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)

(2)


(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)

Grants of Plan Based Awards



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)

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(2)


(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

Employment-Related Agreements with NEOs

Salary and Annual Incentive Compensation in Proportion to Total Compensation

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Outstanding Equity Awards at Fiscal Year-End



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

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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.

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Potential Payments Upon Termination or Change of Control

Employment Agreements

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

◦

Executive Severance Plan

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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.

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."

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."

"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.

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.

Quantification of Potential Payments Upon Termination or Change of Control

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.

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

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)


(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)

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

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

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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.

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)


(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)


(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)


(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



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 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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Preapproval Policies and Procedures

Fees paid to Independent Accounting Firm



	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)).

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†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

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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, ~~2015~~2016 and ~~2014,~~2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2015,~~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 23 to the financial statements, the Company ~~could exceed~~filed voluntary petitions in the ~~Consolidated Funded Debt to consolidated EBITDA financial ratio covenant set forth in its bank credit facility at~~United States Bankruptcy Court for the ~~end~~Southern District of Texas, Houston Division (the "Bankruptcy Court") seeking relief under the provisions of Chapter 11 of Title 11 of the ~~first quarter~~United States Bankruptcy Code to pursue a prepackaged plan of ~~2016, which would require~~reorganization (the "Plan"). The Bankruptcy Court entered an order confirming the Plan on February 15, 2017 and the Company expects the Plan to ~~seek a waiver~~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 ~~amendment from its bank lenders.~~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 2.3. 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, ~~2015,~~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 ~~26, 2016~~23, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February ~~26, 2016~~23, 2017

F-2

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STONE ENERGY CORPORATION

(Debtor-in-Possession)

CONSOLIDATED BALANCE SHEET

(In thousands of dollars)


	December 31,						December 31,
Assets	2015			2014			2016			2015
Current assets:
Cash and cash equivalents	$	10,759		$	74,488		$	190,581		$	10,759
Restricted cash	—			177,647
Accounts receivable	48,031			120,359			48,464			48,031
Fair value of derivative contracts	38,576			139,179			—			38,576
Current income tax receivable	46,174			7,212			26,086			46,174
Inventory	535			3,709
Other current assets	6,346			8,118			10,151			6,881
Total current assets	150,421			530,712			275,282			150,421
Oil and gas properties, full cost method of accounting:
Proved	9,375,898			8,817,268			9,616,236			9,375,898
Less: accumulated depreciation, depletion and amortization	(8,603,955		)	(6,970,631		)	(9,178,442		)	(8,603,955		)
Net proved oil and gas properties	771,943			1,846,637			437,794			771,943
Unevaluated	440,043			567,365			373,720			440,043
Other property and equipment, net of accumulated depreciation of $27,424 and $24,091, respectively	29,289			32,340
Fair value of derivative contracts	—			14,333
Other assets, net of accumulated depreciation and amortization of $4,376 and $3,560, respectively	18,473			18,470
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	$	1,410,169		$	3,009,857		$	1,139,483		$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	82,207		$	132,629		$	19,981		$	82,207
Undistributed oil and gas proceeds	5,992			23,232			15,073			5,992
Accrued interest	9,022			9,022			809			9,022
Deferred taxes	—			20,119
Asset retirement obligations	21,291			69,400			88,000			21,291
Current portion of long-term debt							408			—
Other current liabilities	40,712			49,505			18,602			40,712
Total current liabilities	159,224			303,907			142,873			159,224
Long-term debt	1,060,955			1,032,281			352,376			1,060,955
Deferred taxes	—			286,343
Asset retirement obligations	204,575			247,009			154,019			204,575
Other long-term liabilities	25,204			38,714			17,315			25,204
Total liabilities not subject to compromise							666,583			1,449,958
Liabilities subject to compromise							1,110,182			—
Total liabilities	1,449,958			1,908,254			1,776,765			1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 150,000,000 shares; issued 55,302,325 and 54,884,542 shares, respectively	553			549
Treasury stock (16,582 shares, at cost)	(860		)	(860		)
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	1,648,189			1,633,307			1,659,731			1,648,687
Accumulated deficit	(1,705,623		)	(614,708		)	(2,296,209		)	(1,705,623		)
Accumulated other comprehensive income	17,952			83,315			—			17,952
Total stockholders’ equity	(39,789		)	1,101,603			(637,282		)	(39,789		)
Total liabilities and stockholders’ equity	$	1,410,169		$	3,009,857		$	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,									Year Ended December 31,
	2015			2014			2013			2016			2015			2014
Operating revenue:
Oil production	$	416,497		$	516,104		$	715,104		$	281,246		$	416,497		$	516,104
Natural gas production	83,509			166,494			190,580			64,601			83,509			166,494
Natural gas liquids production	32,322			85,642			60,687			28,888			32,322			85,642
Other operational income	4,369			7,951			7,808			2,657			4,369			7,951
Derivative income, net	7,952			19,351			—			—			7,952			19,351
Total operating revenue	544,649			795,542			974,179			377,392			544,649			795,542
Operating expenses:
Lease operating expenses	100,139			176,495			201,153			79,650			100,139			176,495
Transportation, processing and gathering expenses	58,847			64,951			42,172			27,760			58,847			64,951
Production taxes	6,877			12,151			15,029			3,148			6,877			12,151
Depreciation, depletion and amortization	281,688			340,006			350,574			220,079			281,688			340,006
Write-down of oil and gas properties	1,362,447			351,192			—			357,431			1,362,447			351,192
Accretion expense	25,988			28,411			33,575			40,229			25,988			28,411
Salaries, general and administrative expenses	69,384			66,451			59,524			58,928			69,384			66,451
Franchise tax settlement	—			—			12,590
Incentive compensation expense	2,242			10,361			15,340			13,475			2,242			10,361
Restructuring fees										29,597			—			—
Other operational expenses	2,360			862			151			55,453			2,360			862
Derivative expense, net	—			—			2,090			810			—			—
Total operating expenses	1,909,972			1,050,880			732,198			886,560			1,909,972			1,050,880
Income (loss) from operations	(1,365,323		)	(255,338		)	241,981
Loss from operations										(509,168		)	(1,365,323		)	(255,338		)
Other (income) expenses:
Interest expense	43,928			38,855			32,837			64,458			43,928			38,855
Interest income	(580		)	(574		)	(1,695		)	(550		)	(580		)	(574		)
Other income	(1,783		)	(2,332		)	(2,799		)	(1,439		)	(1,783		)	(2,332		)
Other expense	434			274			—			596			434			274
Loss on early extinguishment of debt	—			—			27,279
Reorganization items										10,947			—			—
Total other expenses	41,999			36,223			55,622			74,012			41,999			36,223
Income (loss) before income taxes	(1,407,322		)	(291,561		)	186,359
Loss before income taxes										(583,180		)	(1,407,322		)	(291,561		)
Provision (benefit) for income taxes:
Current	(44,096		)	159			(10,904		)	(5,674		)	(44,096		)	159
Deferred	(272,311		)	(102,177		)	79,629			13,080			(272,311		)	(102,177		)
Total income taxes	(316,407		)	(102,018		)	68,725			7,406			(316,407		)	(102,018		)
Net income (loss)	$	(1,090,915	)	$	(189,543	)	$	117,634
Basic earnings (loss) per share	$	(19.75	)	$	(3.60	)	$	2.36
Diluted earnings (loss) per share	$	(19.75	)	$	(3.60	)	$	2.36
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	55,250			52,721			48,693			5,591			5,525			5,272
Average shares outstanding assuming dilution	55,250			52,721			48,735			5,591			5,525			5,272



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)



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



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


	Year Ended December 31,							Year Ended December 31,
	2015			2014		2013		2016		2015			2014
	(In thousands)							(In thousands)
Acquisition costs, net of sales of unevaluated properties	$	(17,020	)	$	51,590	$	79,667	$	3,425	$	(17,020	)	$	51,590
Exploratory costs	112,936			289,890		298,932		20,059		112,936			289,890
Development costs (1)	266,982			438,334		378,242		102,665		266,982			438,334
Subtotal	362,898			779,814		756,841		126,149		362,898			779,814
Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements	68,410			76,363		79,354		47,866		68,410			76,363
Total additions to oil and gas properties, net	$	431,308		$	856,177	$	836,195	$	174,015	$	431,308		$	856,177


	Year Ended December 31,						Year Ended December 31,
	2015		2014		2013		2016		2015		2014
Production:
Oil (MBbls)	5,991		5,568		6,894		6,308		5,991		5,568
Natural gas (MMcf)	36,457		47,426		50,129		29,441		36,457		47,426
NGLs (MBbls)	2,401		2,114		1,603		2,183		2,401		2,114
Oil, natural gas and NGLs (MMcfe)	86,809		93,518		101,111		80,387		86,809		93,518
Average sales prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	46.88	$	91.27	$	103.22	$	40.82	$	46.88	$	91.27
Natural gas (per Mcf)	1.90		3.67		3.47		1.80		1.90		3.67
NGLs (per Bbl)	13.46		40.51		37.86		13.23		13.46		40.51
Oil, natural gas and NGLs (per Mcfe)	4.40		8.21		9.36		4.22		4.40		8.21
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	69.52	$	92.69	$	103.73	$	44.59	$	69.52	$	92.69
Natural gas (per Mcf)	2.29		3.51		3.80		2.19		2.29		3.51
NGLs (per Bbl)	13.46		40.51		37.86		13.23		13.46		40.51
Oil, natural gas and NGLs (per Mcfe)	6.13		8.21		9.56		4.66		6.13		8.21
Expenses (per Mcfe):
Lease operating expenses (1)	$	1.15	$	1.89	$	1.99	$	0.99	$	1.15	$	1.89
Transportation, processing and gathering expenses	0.68		0.69		0.42		0.35		0.68		0.69


(1)	Includes capitalized asset retirement costs of ($~~43,901)~~4,461), ($~~20,305)~~43,901) and ~~$54,737~~($20,305) for the years ended December 31, 2016, 2015 ~~2014~~ and ~~2013,~~2014, respectively.


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


	Year Ended December 31,						Year Ended December 31,
FIELD: Pompano (1)	2015		2014		2013		2016		2015		2014
Production:
Oil (MBbls)	2,839		1,311		1,420		3,858		2,994		1,311
Natural gas (MMcf)	3,331		2,894		2,887		7,882		3,466		2,894
NGLs (MBbls)	239		151		162		267		245		151
Oil, natural gas and NGLs (MMcfe)	21,799		11,666		12,375		32,629		22,902		11,666
Average sales prices:
Oil (per Bbl)	$	49.19	$	92.53	$	107.99	$	41.86	$	49.18	$	92.53
Natural gas (per Mcf)	2.22		3.10		2.49		2.15		2.17		3.10
NGLs (per Bbl)	15.49		41.27		40.65		12.46		15.28		41.27
Oil, natural gas and NGLs (per Mcfe)	6.91		11.70		13.50		5.57		6.92		11.70
Expenses (per Mcfe):
Lease operating expenses (2)	$	0.96	$	2.75	$	1.98	$	0.78	$	0.91	$	2.75
Transportation, processing and gathering expenses	0.08		0.13		0.14		0.10		0.07		0.13


(1)	Includes the Pompano, Cardona and Amethyst fields, all of which tie ~~back, or will be tied~~ back to the Pompano platform.



	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.



	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



	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


	High		Low		High		Low
2014
First Quarter	$	42.86	$	29.13
Second Quarter	50.00		39.88
Third Quarter	47.11		29.95
Fourth Quarter	32.05		12.96
2015
First Quarter	$	18.98	$	12.07	$	189.80	$	120.70
Second Quarter	19.65		12.33		196.50		123.30
Third Quarter	12.50		3.74		125.00		37.40
Fourth Quarter	9.84		3.06		98.40		30.60
2016
First Quarter (through February 22, 2016)	$	4.66	$	1.80
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



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 (1)	Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
October 1 – October 31, 2015	—	$—	—
November 1 – November 30, 2015	—	—	—
December 1 – December 31, 2015	—	—	—
	—	$—	—	$	92,928,632


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


Measurement Period (Fiscal Year Covered)	SGY	2015 Peer Group	S&P 500 Index	SGY	2016 Peer Group	S&P 500 Index
12/31/2011	118.35	89.72	102.11
12/31/2012	92.06	82.48	118.45	77.79	91.93	116.00
12/31/2013	155.18	108.97	156.82	131.12	121.45	153.57
12/31/2014	75.73	72.88	178.29	63.99	81.23	174.60
12/31/2015	19.25	43.44	180.75	16.26	48.42	177.01
12/31/2016				2.71	68.01	198.18


(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 ~~and no shares withheld from employees or nonemployee directors to pay taxes associated with any vesting of restricted stock~~ during the fourth quarter of ~~2015.~~2016.


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.


Year Ended December 31,	Safety Performance	Safety Goal	Safety Performance	Safety Goal
2016			0.28	0.30
2015	0.14	0.30	0.14	0.30
2014	0.00	0.50	0.00	0.50
2013	0.47	0.50


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


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


											Payments Due By Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years		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	$	—	$	—	$	300,000	$	300,000	$	—	$	—	$	—
7 1⁄2% Senior Notes due 2022	775,000		—		—		—		775,000		775,000		—		—		—		775,000
Revolving Credit Facility											341,500		—		341,500		—		—
4.20% Building Loan	11,771		391		833		906		9,641		11,379		408		868		944		9,159
Interest and commitment fees (1)	426,305		65,695		123,454		118,006		119,150		32,092		11,456		17,320		811		2,505
Asset retirement obligations including accretion	741,111		20,840		202,478		18,785		499,008		664,674		127,260		70,349		36,176		430,889
Rig commitments (2)	149,242		89,505		59,737		—		—		12,650		12,650		—		—		—
Seismic data commitments	36,438		21,058		15,380		—		—		15,380		7,690		7,690		—		—
Operating lease obligations	4,462		2,022		1,421		906		113		2,508		877		1,065		566		—
Total Contractual Obligations and Commitments	$	2,444,329	$	199,511	$	703,303	$	138,603	$	1,402,912	$	2,155,183	$	460,341	$	438,792	$	38,497	$	1,217,553


(1)	Includes interest payable on the ~~2017 Convertible Notes, 2022 Notes~~bank credit facility and Building Loan. Assumes ~~0.375%~~0.50% fee on unused commitments under the bank credit facility.


(2)	Represents minimum committed future expenditures for drilling rig services. Amounts do not assume any farm-out arrangements with other operators for the ENSCO 8503 deep water drilling rig. We have successfully executed one rig farm-out arrangement for the ENSCO 8503 with another operator for approximately 60 to 90 days, commencing in late February 2016.



	Fixed-Price Swaps (NYMEX)
	Natural Gas		Oil
	Daily Volume (MMBtus/d)	Swap Price ($/MMBtu)	Daily Volume (Bbls/d)	Swap Price ($/Bbl)
2016	10,000	4.110	1,000	49.75
2016	10,000	4.120	1,000	52.78
2016			1,000	90.00



	Costless Collar (NYMEX)
	Oil
	Daily Volume (Bbls/d)	Floor Price ($)	Ceiling Price ($)
2016	1,000	45.00	54.75



~~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, 2015 (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).~~

~~†10.3~~	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)).

~~†10.4~~	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)).

~~†10.5~~	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)).

~~†10.6~~	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)).

~~†10.7~~	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)).

~~†10.8~~	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)).

~~†10.9~~	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)).

~~†10.10~~	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)).

~~10.11~~	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)).

~~10.12~~	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)).



~~10.13~~	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)).

~~10.14~~	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)).

~~10.15~~	Base Bond Hedge Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.16~~	Base Bond Hedge Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.17~~	Additional Bond Hedge Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.18~~	Additional Bond Hedge Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.19~~	Base Warrant Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.20~~	Base Warrant Confirmation dated as of February 29, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.21~~	Additional Warrant Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.22~~	Additional Warrant Confirmation dated as of March 2, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.23~~	Amendment to Base Warrant Confirmation and Additional Warrant Confirmation dated March 5, 2012, by and between Stone Energy Corporation and Barclays Capital Inc., acting as agent for Barclays Bank PLC (incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

~~10.24~~	Amendment to Base Warrant Confirmation and Additional Warrant Confirmation dated March 5, 2012, by and between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K filed March 6, 2012 (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.~~


	Common Stock		Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity			Common Stock		Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance, December 31, 2012	$	484	$	(860	)	$	1,386,475		$	(542,799	)	$	28,833		$	872,133
Net income	—		—			—			117,634			—			117,634
Adjustment for fair value accounting of derivatives, net of tax	—		—			—			—			(30,228		)	(30,228		)
Adjustment for foreign currency translation, net of tax	—		—			—			—			(667		)	(667		)
Exercise of stock options and vesting of restricted stock	4		—			(3,130		)	—			—			(3,126		)
Amortization of stock compensation expense	—		—			15,424			—			—			15,424
Net tax impact from stock option exercises and restricted stock vesting	—		—			(884		)	—			—			(884		)
Balance, December 31, 2013	488		(860		)	1,397,885			(425,165		)	(2,062		)	970,286			$	49	$	(860	)	$	1,398,324		$	(425,165	)	$	(2,062	)	$	970,286
Net loss	—		—			—			(189,543		)	—			(189,543		)	—		—			—			(189,543		)	—			(189,543		)
Adjustment for fair value accounting of derivatives, net of tax	—		—			—			—			88,178			88,178			—		—			—			—			88,178			88,178
Adjustment for foreign currency translation, net of tax	—		—			—			—			(2,801		)	(2,801		)	—		—			—			—			(2,801		)	(2,801		)
Exercise of stock options and vesting of restricted stock	3		—			(7,174		)	—			—			(7,171		)	—		—			(7,119		)	—			—			(7,119		)
Amortization of stock compensation expense	—		—			16,709			—			—			16,709			—		—			16,709			—			—			16,709
Net tax impact from stock option exercises and restricted stock vesting	—		—			(54		)	—			—			(54		)	—		—			(54		)	—			—			(54		)
Issuance of common stock	58		—			225,941			—			—			225,999			6		—			225,941			—			—			225,947
Balance, December 31, 2014	549		(860		)	1,633,307			(614,708		)	83,315			1,101,603			55		(860		)	1,633,801			(614,708		)	83,315			1,101,603
Net loss	—		—			—			(1,090,915		)	—			(1,090,915		)	—		—			—			(1,090,915		)	—			(1,090,915		)
Adjustment for fair value accounting of derivatives, net of tax	—		—			—			—			(62,758		)	(62,758		)	—		—			—			—			(62,758		)	(62,758		)
Adjustment for foreign currency translation, net of tax	—		—			—			—			(2,605		)	(2,605		)	—		—			—			—			(2,605		)	(2,605		)
Exercise of stock options and vesting of restricted stock	4		—			(2,642		)	—			—			(2,638		)	—		—			(2,638		)	—			—			(2,638		)
Amortization of stock compensation expense	—		—			17,524			—			—			17,524			—		—			17,524			—			—			17,524
Balance, December 31, 2015	$	553	$	(860	)	$	1,648,189		$	(1,705,623	)	$	17,952		$	(39,789	)	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	)



	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


	As of December 31,				As of December 31,
	2015		2014		2016		2015
Other co-venturers	$	4,639	$	16,291	$	3,532	$	4,639
Trade	26,224		60,263		42,944		26,224
Unbilled accounts receivable	1,736		33,052		591		1,736
Other	15,432		10,753		1,397		15,432
Total accounts receivable	$	48,031	$	120,359	$	48,464	$	48,031



		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

														Fair Value of Derivatives Qualifying as Hedging Instruments at
December 31, 2014
December 31, 2015							December 31, 2015
	Asset Derivatives			Liability Derivatives				Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts	$	127,033	Current liabilities: Fair value of derivative 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	14,333		Long-term liabilities: Fair value of derivative contracts	—			Long-term assets: Fair value of derivative contracts	—		Long-term liabilities: Fair value of derivative contracts	—
		$	141,366		$	—			$	38,576		$	—