Edgar Filing: STONE ENERGY CORP

10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2015

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

For the transition period from to

Commission File Number: 1-12074

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)



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

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

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



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

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

None

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

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

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

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

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

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



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

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

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $695.9 million as of June 30, 2015 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

As of February 22, 2016, the registrant had outstanding 56,849,335 shares of Common Stock, par value $.01 per share.

Documents incorporated by reference: Portions of the Definitive Proxy Statement of Stone Energy Corporation relating to the Annual Meeting of Stockholders to be held on May 19, 2016 are incorporated by reference into Part III of this Form 10-K.

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TABLE OF CONTENTS



		Page No.
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	23
Item 2.	Properties	23
Item 3.	Legal Proceedings	29
Item 4.	Mine Safety Disclosures	29

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 8.	Financial Statements and Supplementary Data	47
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	47
Item 9A.	Controls and Procedures	47
Item 9B.	Other Information	50

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	50
Item 11.	Executive Compensation	50
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 13.	Certain Relationships and Related Transactions, and Director Independence	50
Item 14.	Principal Accountant Fees and Services	50

PART IV

Item 15.	Exhibits and Financial Statement Schedules	51
	Index to Financial Statements	F-1
	Glossary of Certain Industry Terms	G-1

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PART I

This section highlights information that is discussed in more detail in the remainder of the document. Throughout this document, we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section beginning on page 9 of this document for an explanation of these types of statements. We use the terms “Stone,” “Stone Energy,” “company,” “we,” “us” and “our” to refer to Stone Energy Corporation and its consolidated subsidiaries. Certain terms relating to the oil and gas industry are defined in “Glossary of Certain Industry Terms,” which begins on page G-1 of this Annual Report on Form 10-K (this “Form 10-K”).

ITEM 1. BUSINESS

The Company

Stone Energy is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf of Mexico (the “GOM”) Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. As of December 31, 2015, our estimated proved oil and natural gas reserves were approximately 57 MMBoe or 342 Bcfe. During 2015, approximately 95 MMBoe or 570 Bcfe of our estimated proved reserves were revised downward as a result of lower oil, natural gas and natural gas liquids ("NGL") prices.

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 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. We plan to continuously evaluate our level of operating activity in light of both actual commodity prices and changes we are able to make to our costs of operations, and may make further adjustments to our cost structure and capital expenditure program as appropriate. 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% of our estimated proved oil and natural gas reserves at December 31, 2015 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 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% of our estimated proved oil and natural gas reserves at December 31, 2015 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, we have significantly reduced our exposure to 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% of our estimated proved oil and natural gas reserves at December 31, 2015 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 on September 1, 2015, curtailing approximately 100 MMcfe per day of production. Additionally, we suspended completion operations on 23 drilled wells until pricing and margin improvements can be realized. Our 2016 capital expenditure budget assumes only minimal activity in Appalachia, which will entail lease maintenance expenditures and satisfying obligations under our Appalachian rig commitment.

Business Development

In prior years, the business development effort was focused on providing Stone with exposure to new or unproven plays that could add significant value to the company if successful. Given the uncertainty regarding future commodity prices, we have allocated only a minimal portion of our 2016 capital expenditure budget 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% and 13%, respectively, of our oil and natural gas revenue generated during the year ended December 31, 2015. 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 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 operations on federal leases. All of 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 can order the pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Outer Continental Shelf Regulation. Our operations on federal oil and gas leases in the GOM are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Bureau of Ocean Energy Management (“BOEM”). These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act. These laws and regulations are subject to change, and many new requirements were imposed by the BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Outer Continental Shelf (“OCS”), calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. These rules are frequently subject to change. For example, in April 2015, BSEE released a proposed rule containing more stringent standards relating to well control equipment used in connection with offshore well drilling operations. The proposed standards focus on blowout preventers, along with well design, well control, casing, cementing, real-time well monitoring, and subsea containment requirements. 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 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 Notice to Lessees (“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.

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 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.

Natural Gas. In 2005, the United States Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (the “NGA”) to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as Stone Energy, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (the “FERC”), in contravention of rules prescribed by the FERC. In 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the

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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 connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. The U.S. Commodity Futures Trading Commission (the “CFTC”) has similar authority with respect to energy futures commodity markets. Stone Energy does not anticipate it will be affected any differently by these requirements than other producers of natural gas.

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, including producers, from effectively competing with 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, the natural gas pipeline industry is also subject to state regulations, which may change from time to time in ways that affect the availability, terms and cost of transportation. However, we do not believe that any such changes would affect our business in a way that would be materially different from the way such changes would affect our competitors.

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

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

Waste handling. The Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to regulatory guidance issued by the federal EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA's exemption of certain oil and gas wastes from RCRA. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (the “CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for 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 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 treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and wastes disposed thereon may be subject to laws and regulations imposing strict, joint and several liability, without regard to fault or the legality of the original conduct, that could require us to remove or remediate previously disposed wastes or environmental contamination, or to perform remedial plugging or pit closure to prevent future contamination.

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

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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” 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”). 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, in December 2015, 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, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already taken legal measures to reduce emissions of greenhouse gases primarily through regional 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 could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. 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 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 Interior 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 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 Water Act”) and analogous state laws, impose restrictions and strict controls with respect to the monitoring and discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants 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.

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, 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. The federal Endangered Species Act (“ESA”) provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened 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. 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. Fish and Wildlife Service (the “USFWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas and oil development. Moreover, as a result of a settlement, the USFWS is 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 property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration 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.

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 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, we had 310 full-time employees. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement. We utilize the services of independent contractors to perform various daily operational duties.

Available Information

We make available free of charge on our Internet website (www.stoneenergy.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). We also make available on our Internet website our Code of Business Conduct and Ethics, Corporate Governance Guidelines and Audit, Compensation and Nominating and Governance Committee Charters, which have been approved by our board of directors. Copies of these documents are also available free of charge by writing us at: Chief Financial Officer, Stone Energy Corporation, P.O. Box 52807, Lafayette, LA 70505. The annual CEO certification required by Section 303A.12 of the New York Stock Exchange Listed Company Manual was submitted on June 16, 2015.

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” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Exchange Act. All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K.

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


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


•	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.

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


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


•	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, raise additional capital or seek bankruptcy protection;


•	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 bank credit facility and impairments;


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


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


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


•	third-party interruption of sales to market;


•	inflation;


•	lack of availability and cost of goods and services;


•	market conditions relating to potential acquisition and divestiture transactions;


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


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

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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;


•	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;


•	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 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:

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 throughout 2015 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, our Mary field in Appalachia has been shut-in since September 1, 2015, due to low prices for natural gas and NGLs, and high midstream costs. 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, the West Texas Intermediate (“WTI”) crude oil price per Bbl ranged from a low of $34.73 to a high of $110.53, and the New York Mercantile Exchange (“NYMEX”) natural gas price per MMBtu ranged from a low of $1.76 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.

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 2015, BSEE released a proposed rule containing more stringent standards relating to well control equipment used in connection with offshore well drilling operations. The proposed standards focus on blowout preventers, along with well design, well control, casing, cementing, real-time well monitoring, and subsea containment requirements. 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.

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.

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, 2015 on historical 12-month average prices and costs as of the date of the estimate.

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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 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;


•	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, 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 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.

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 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 filing under Chapter 11 of the U.S. Bankruptcy Code. Seeking Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as a proceeding related to a Chapter 11 proceeding continues, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing on our business operations. Bankruptcy Court protection also might make it more difficult to retain management and other key personnel necessary to 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.

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Additionally, we may have a significant amount of secured indebtedness that is senior to our unsecured indebtedness and a significant amount of total indebtedness that is senior to our existing common stock in our capital structure. As a result, we believe that seeking Bankruptcy Court protection under a Chapter 11 proceeding could result in a limited recovery for unsecured noteholders, if any, and place equity holders at significant risk of losing all of their interests in the company.

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

Approximately 56% of our production during 2015 was associated with our GOM deep water, Gulf Coast deep gas and GOM conventional shelf properties. 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 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 of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling, therefore there is additional risk of expirations occurring in those sections.

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

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

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

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

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 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. 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.

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 the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our financial condition and operations.

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.

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, 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.

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.

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.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development. Additionally, future federal and state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. 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. The passage of this legislation or any other similar changes in U.S. federal and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our common stock. Additionally, legislation could be enacted that increases the taxes states impose on oil 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.

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

The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases contribute to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources through preconstruction and operating permit requirements. 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, in December 2015, 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. In addition, the Obama Administration has directed a number of federal agencies to propose new rules to control fugitive emissions of greenhouse gases including methane, and VOCs. For example, 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 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.

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

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

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Colombia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swap contracts for, or linked to, certain physical commodities, subject to exceptions for certain bona fide hedging transactions. 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 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 and state legislation and regulatory initiatives relating to hydraulic fracturing could cause us to incur increased costs and experience additional operating restrictions 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 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 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.

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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 amount of oil and natural gas that we are ultimately able to produce from our reserves.

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 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

As of February 22, 2016, our property portfolio consisted of nine active properties and 103 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. The properties that we operate accounted for 94% of our year-end 2015 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

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management but may not delegate these responsibilities. The reserves committee provides oversight in regards to the reserve 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 were independently prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI letter, which is filed as an exhibit to this Form 10-K, were Lily W. Cheung, Vice President and Team Leader, and Edward C. Roy III, Vice President. Ms. Cheung is a Registered Professional Engineer in the State of Texas (License No. 107207). Ms. Cheung joined NSAI in 2007 after serving as an Engineer at ExxonMobil Production Company. Ms. Cheung’s areas of specific expertise include estimation of oil and gas reserves, drilling and workover prospect evaluation, and economic evaluations. Ms. Cheung received an MBA degree from University of Texas at Austin in 2007 and a BS degree in Mechanical Engineering from Massachusetts Institute of Technology in 2003. Mr. Roy is a Registered Professional Geoscientist in the State of Texas (License No. 2364). Mr. Roy joined NSAI in 2008 after serving as a Senior Geologist at Marathon Oil Company. Mr. Roy’s areas of specific expertise include deep-water stratigraphy, seismic interpretation and attribute analysis, volumetric reserve estimation, and probabilistic analysis. Mr. Roy received a MS degree in Geology from Texas A&M University in 1998 and a BS degree in Geology from Texas Christian University in 1992. Ms. Cheung and Mr. Roy both meet or exceed the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; they are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

The following table sets forth our estimated proved oil and natural gas reserves (approximately 99% of which are located in the GOM and 1% in the Appalachian region) as of December 31, 2015. The 2015 average 12-month oil and natural gas prices net of differentials were $51.16 per Bbl of oil, $16.40 per Bbl of NGLs and $2.19 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
	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
Undeveloped	8,542	1,674	31,596	92,894
TOTAL PROVED	30,276	6,458	121,858	342,260

At December 31, 2015, we reported estimated proved undeveloped reserves (“PUDs”) of 92.9 Bcfe, which accounted for 27% of our total estimated proved oil and natural gas reserves. This figure ties to a projected two new wells (27.0 Bcfe) and six sidetrack wells from existing wellbores (65.9 Bcfe). We expect two or three of the sidetrack wells to be drilled in 2016, while the timetable for drilling of the remaining sidetrack wells is totally dependent on the life of the currently producing zones. After the current zones have been depleted, we would utilize the existing wellbore to sidetrack to the PUD objective. Regarding the remaining two PUD locations, we project one well to be drilled in 2016 (16.8 Bcfe) and one well in 2018 (10.2 Bcfe). Neither of these two 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.

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	Oil, Natural Gas and NGLs (MMcfe)		Future Development Costs (in thousands)
PUDs beginning of year	445,006		$	895,289
Revisions of previous estimates	(352,112	)	(713,335		)
Conversions to proved developed reserves	—		—
Additional PUDs added	—		—
PUDs end of year	92,894		$	181,954

During 2015, we recognized downward revisions of 352 Bcfe of previously booked PUDs due primarily to the effects of lower commodity prices. As of December 31, 2015, we had no PUDs in the Appalachia region.

The following represents additional information on our significant properties:



			December 31, 2015
		2015	Estimated
Field Name	Location	Production (MMcfe)	Proved Reserves (MMcfe)	Nature of Interest
Pompano (1)	GOM Deep Water	21,799	264,212	Working
Mary (2)	Appalachia	29,050	—	Working
Mississippi Canyon Block 109	GOM Deep Water	6,684	43,004	Working
Bayou Hebert	Gulf Coast Deep Gas	5,489	18,922	Working
Main Pass Block 288	GOM Shelf	3,110	10,810	Working
Heather	Appalachia	9,052	1,595	Working
Ship Shoal Block 113	GOM Shelf	6,764	1,198	Working


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


(2)	At December 31, 2014 our Mary field accounted for approximately 52% of our estimated proved oil and natural gas reserves, on a volume equivalent basis. At December 31, 2015, however, all of our Mary field reserves were removed from proved reserves due to the effect of reduced commodity prices.

Low commodity prices during 2015 have adversely impacted the estimated value and quantities of our proved oil, natural gas and NGL reserves. Commodity prices continued to decline throughout 2015 and into 2016, which will have further negative effects on the average prices used in our proved reserve estimates and on the estimated value and quantities of our proved reserves. For example, we estimate that if NYMEX commodity prices remain at current levels (approximately $30 per Bbl of oil and $2.00 per MMBtu of natural gas), we would reasonably expect to incur further downward revisions of our estimated proved reserve quantities between 18 - 36 Bcfe in the first quarter of 2016.

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

As an operator of domestic oil and gas properties, we have filed U.S. Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,” as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The differences are attributable to the fact that Form EIA-23 requires that an operator report the

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total reserves attributable to wells that it operates, without regard to percentage ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis) or non-operated wells in which it owns an interest.

Acquisition, Production and Drilling Activity

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



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


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

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



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


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

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Production Volumes, Sales Price and Cost Data for Individually Significant Fields. The following table sets forth certain information regarding our oil, natural gas and NGL production volumes, sales prices and average production costs for the periods indicated for any field(s) containing 15% or more of our total estimated proved reserves at December 31, 2015.



	Year Ended December 31,
FIELD: Pompano (1)	2015		2014		2013
Production:
Oil (MBbls)	2,839		1,311		1,420
Natural gas (MMcf)	3,331		2,894		2,887
NGLs (MBbls)	239		151		162
Oil, natural gas and NGLs (MMcfe)	21,799		11,666		12,375
Average sales prices:
Oil (per Bbl)	$	49.19	$	92.53	$	107.99
Natural gas (per Mcf)	2.22		3.10		2.49
NGLs (per Bbl)	15.49		41.27		40.65
Oil, natural gas and NGLs (per Mcfe)	6.91		11.70		13.50
Expenses (per Mcfe):
Lease operating expenses (2)	$	0.96	$	2.75	$	1.98
Transportation, processing and gathering expenses	0.08		0.13		0.14


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


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

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



	Year Ended December 31,
	2015		2014		2013
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive	2	0.25	5	4.31	2	0.60
Dry	2	0.42	2	0.90	2	0.65
Development Wells:
Productive	7	5.81	38	33.35	44	28.13
Dry	—	—	—	—	1	0.94

During the period beginning January 1, 2016 and ending February 22, 2016, we participated in the drilling of one gross (one net) development well.

Productive Well and Acreage Data. The following table sets forth certain statistics regarding the number of productive wells and developed and undeveloped acreage as of December 31, 2015.

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	Gross	Net
Productive Wells:
Oil (1):
Deep Water	49	43
Deep Gas	—	—
Conventional Shelf	29	29
Appalachia	—	—
Other	—	—
	78	72
Gas:
Deep Water	5	4
Deep Gas	5	1
Conventional Shelf	7	6
Appalachia	136	95
Other	—	—
	153	106
Total productive wells	231	178

Developed Acres:
Deep Water	108,680	62,967
Deep Gas	29,697	6,698
Conventional Shelf	72,657	52,834
Appalachia	49,157	41,028
Canada	—	—
Other	7,496	2,465
	267,687	165,992
Undeveloped Acres (2):
Deep Water	491,533	300,315
Deep Gas	7,478	3,910
Conventional Shelf	10,132	7,643
Appalachia	60,433	47,647
Canada	142,289	70,789
Other	64,953	18,700
	776,818	449,004
Total developed and undeveloped acres	1,044,505	614,996

(1) 5 gross wells each have dual completions.

(2) Leases covering approximately 15% of our undeveloped gross acreage will expire in 2016, 9% in 2017, 25% in 2018, 26% in 2019, 6% in 2020, 2% in 2021, 4% in 2022 and 8% thereafter.

As of December 31, 2015, none of our PUDs were assigned to locations that are currently scheduled to be drilled after lease expiration.

Title to Properties

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

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ITEM 3. LEGAL PROCEEDINGS

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

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, “the CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone, and related costs and attorney’s fees.

In addition, on November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. On November 12, 2015, the Plaquemines Parish Council passed a resolution instructing its attorneys to dismiss all 21 Coastal Zone Management suits filed by the Plaquemines Parish. To date, counsel for the Plaquemines Parish has not yet moved to dismiss the cases. On January 12, 2016, Stone moved to dismiss the action without prejudice. Plaintiff has not yet opposed the motion.

On October 10, 2012, Stone received notice from the BSEE that it was initiating an enforcement proceeding with respect to an Incident of Non-Compliance observed at Stone's Vermillion Block 255 H Platform on April 19, 2012. Stone does not agree that the conditions observed were violations of applicable rules. BSEE issued a Reviewing Officer’s Final Decision dated July 9, 2013, assessing a penalty against Stone of $200,000, which was calculated as $25,000 per day for eight days of alleged improper venting of gas at the platform. On August 12, 2015, the Interior Board of Land Appeals affirmed the penalty. Stone's appeal to the Director of the Department of the Interior Office of Hearings and Appeals is pending. Stone does not believe that this proceeding will have a material adverse effect on our financial condition or results of operations.

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

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Since July 9, 1993, our common stock has been listed on the New York Stock Exchange under the symbol “SGY.” The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock.



	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
Second Quarter	19.65		12.33
Third Quarter	12.50		3.74
Fourth Quarter	9.84		3.06
2016
First Quarter (through February 22, 2016)	$	4.66	$	1.80

On February 22, 2016, the last reported sales price of our common stock on the New York Stock Exchange Composite Tape was $1.85 per share. As of that date, there were 450 holders of record of our common stock.

Dividend Restrictions

In the past, we have not paid cash dividends on our common stock, and we do not intend to pay cash dividends on our common stock in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and development of our business. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the indentures executed in connection with our 1 3⁄4% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”) and our 7 1⁄2% Senior Notes due 2022 (the “2022 Notes”). In addition, our bank credit facility contains provisions that may have the effect of limiting or prohibiting the payment of dividends.

Issuer Purchases of Equity Securities

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program. The following table sets forth information regarding our repurchases or acquisitions of our common stock during the fourth quarter of 2015:

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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


(1)	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.

Equity Compensation Plan Information

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

Stock Performance Graph

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


1.	$100 was invested in the company’s common stock, the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Peer Group (as defined below) on December 31, 2010 at $22.29 per share for the company’s common stock and at the closing price of the stocks comprising the S&P 500 Index and the Peer Group, respectively, on such date.


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


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

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Measurement Period (Fiscal Year Covered)	SGY	2015 Peer Group	S&P 500 Index
12/31/2011	118.35	89.72	102.11
12/31/2012	92.06	82.48	118.45
12/31/2013	155.18	108.97	156.82
12/31/2014	75.73	72.88	178.29
12/31/2015	19.25	43.44	180.75

The companies that comprised our Peer Group in 2015 were: Cabot Oil & Gas Corporation, Callon Petroleum Company, Carrizo Oil & Gas, Inc., Cimarex Energy Company, Comstock Resources, Inc., Contango Oil & Gas Company, Denbury Resources Inc., Energy XXI Ltd., Exco Resources Inc., Newfield Exploration Company, PDC Energy, PetroQuest Energy, Inc., Range Resources Corporation, SandRidge Energy, Inc., SM Energy Company, Swift Energy Company, Ultra Petroleum Corporation, W&T Offshore, Inc. and Whiting Petroleum Corporation. The 2015 Peer Group was the same as our 2014 peer group, however, EPL Oil & Gas, Inc. was acquired by Energy XXI Ltd. in mid-2014.

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

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2015. This information is derived from our Consolidated Financial Statements and the notes thereto. Certain prior year amounts have been reclassified to conform to current year presentation. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.



	Year Ended December 31,
	2015			2014			2013			2012			2011
Income Statement Data:	(In thousands, except per share amounts)
Operating revenue:
Oil production	$	416,497		$	516,104		$	715,104		$	761,304		$	663,958
Natural gas production	83,509			166,494			190,580			134,739			170,611
Natural gas liquids production	32,322			85,642			60,687			48,498			29,996
Other operational income	4,369			7,951			7,808			3,520			3,938
Derivative income, net	7,952			19,351			—			3,428			1,418
Total operating revenue	544,649			795,542			974,179			951,489			869,921
Operating expenses:
Lease operating expenses	100,139			176,495			201,153			215,003			175,881
Transportation, processing, gathering expenses	58,847			64,951			42,172			21,782			8,958
Production taxes	6,877			12,151			15,029			10,015			9,380
Depreciation, depletion and amortization	281,688			340,006			350,574			344,365			280,020
Write-down of oil and gas properties	1,362,447			351,192			—			—			—
Accretion expense	25,988			28,411			33,575			33,331			30,764
Salaries, general and administrative expenses	69,384			66,451			59,524			54,648			40,169
Franchise tax settlement	—			—			12,590			—			—
Incentive compensation expense	2,242			10,361			15,340			8,113			11,600
Other operational expenses	2,360			862			151			267			2,149
Derivative expense, net	—			—			2,090			—			—
Total operating expenses	1,909,972			1,050,880			732,198			687,524			558,921
Income (loss) from operations	(1,365,323		)	(255,338		)	241,981			263,965			311,000
Other (income) expenses:
Interest expense	43,928			38,855			32,837			30,375			9,289
Interest income	(580		)	(574		)	(1,695		)	(600		)	(420		)
Other income	(1,783		)	(2,332		)	(2,799		)	(1,805		)	(1,942		)
Other expense	434			274			—			—			—
Loss on early extinguishment of debt	—			—			27,279			1,972			607
Total other expenses	41,999			36,223			55,622			29,942			7,534
Income (loss) before income taxes	(1,407,322		)	(291,561		)	186,359			234,023			303,466
Income tax provision (benefit)	(316,407		)	(102,018		)	68,725			84,597			109,134
Net income (loss)	$	(1,090,915	)	$	(189,543	)	$	117,634		$	149,426		$	194,332
Earnings and dividends per common share:
Basic earnings (loss) per share	$	(19.75	)	$	(3.60	)	$	2.36		$	3.03		$	3.97
Diluted earnings (loss) per share	$	(19.75	)	$	(3.60	)	$	2.36		$	3.03		$	3.97
Cash dividends declared per share	—			—			—			—			—
Cash Flow Data:
Net cash provided by operating activities	$	247,474		$	401,141		$	594,205		$	509,749		$	570,850
Net cash used in investing activities	(321,290		)	(872,587		)	(623,036		)	(568,688		)	(679,250		)
Net cash provided by financing activities	10,161			215,446			80,594			300,014			39,895
Balance Sheet Data (at end of period):
Working capital (deficit)	$	(8,803	)	$	226,805		$	181,255		$	300,348		$	(13,282	)
Oil and gas properties, net	1,211,986			2,414,002			2,619,696			2,182,095			1,875,048
Total assets	1,410,169			3,009,857			3,238,117			2,750,987			2,154,616
Long-term debt, less current portion	1,060,955			1,032,281			1,016,645			888,682			608,865
Stockholders’ equity	(39,789		)	1,101,603			970,286			872,133			667,829

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

The following discussion is intended to assist in understanding our financial position and results of operations for each of the years in the three-year period ended December 31, 2015. Our Consolidated Financial Statements and the notes thereto, which are found elsewhere in this Form 10-K, contain detailed information that should be referred to in conjunction with the following discussion. See Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data – Note 1.

Executive Overview

We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the GOM Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. See Item 1. Business – Operational Overview.

2015 Significant Events.

Declining Realized Prices – During the second half of 2014 and throughout 2015, oil, natural gas and NGL prices experienced a significant decline that continued into 2016. The resulting reduction in our revenue and cash flows caused us to reduce our planned capital expenditures for 2015 and 2016. Additionally, the low commodity prices materially adversely affected the estimated value and quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties.

Deepwater Operations – In 2015, we drilled our third successful deep water well at Cardona, bringing net oil production at the Cardona field to approximately 8,600 Bbls per day. In December 2015, we concluded completion operations at our Amethyst well, located in Mississippi Canyon block 26, with production commencing in late December 2015.

Appalachian Operations – We have been shut-in in our Mary field in Appalachia since September 1, 2015 due to low commodity prices and high midstream costs, curtailing approximately 100 MMcfe of production per day. We currently have 23 drilled wells where completion operations have been suspended until pricing and margin improvements can be realized. Despite the shut-in of the Mary field in September 2015, we achieved our highest annual rate of approximately 107 MMcfe of production per day from our Appalachian properties in 2015.

2016 Outlook.

Liquidity – The level of our indebtedness of approximately $1,137 million and the current commodity price environment will present challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. 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 agreement at the end of the first quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. 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.

As of February 22, 2016, we had total indebtedness of $1,137 million, including $300 million face value of 2017 Convertible Notes and $775 million of 2022 Notes. We are actively reviewing various financing, asset sales and debt restructuring alternatives to provide additional and adequate longer term liquidity and to address the March 1, 2017 maturity of the 2017 Convertible Notes.

Although we are currently exempt from the existing federal supplemental bonding requirements imposed by the BOEM on our offshore abandonment obligations, we expect to lose that exemption in 2016, as suppressed commodity prices have negatively affected our net worth. If we cannot qualify for a waiver, we may need to obtain surety bonds or some other form of financial assurance, which could impact our liquidity. See "Known Trends and Uncertainties."

2016 Capital Expenditures – Our 2016 board authorized capital expenditure budget is $200 million, which assumes success in farming out the ENSCO 8503 deep water drilling rig to other operators for five to six months and the reduction in our working interests to acceptable levels on potential exploration wells to be drilled or stacking the rig. In addition to the $200 million in budgeted capital expenditures, the farm-out subsidies and rig stacking expenses would be charges to our statement of operations as "Other operational expenses" and could range between $40 and $50 million. We have already successfully executed one rig farm-out arrangement for the ENSCO 8503 with another operator for approximately 60 to 90 days, commencing in late February

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2016. We continue to pursue additional opportunities to farm-out the rig and anticipate that we may execute a second, separate farm-out agreement for another 90 to 120 days with another operator, which would immediately follow the currently scheduled farm-out. The $200 million 2016 capital expenditure budget compares with a 2015 board authorized capital expenditure budget of $450 million, a reduction of approximately 56%, and excludes material acquisitions, capitalized salaries, general and administrative (“SG&A”) expenses and capitalized interest as well as potential subsidy expense associated with rig farm-outs and rig stacking charges.

Proposed expenditures for 2016 are primarily tied to the Pompano platform rig development program and the utilization of the ENSCO 8503 rig for a development well and possibly one or two exploration wells. The drilling of the exploration wells is dependent upon our ability to reduce our working interests in the prospects. Our 2016 capital expenditure budget includes minimal activity in the Appalachian basin, satisfying regulatory abandonment commitments, and contractual seismic and leasehold commitments. The budget is allocated approximately 80%-85% to the GOM Basin, 3%-5% to Appalachia, and 10%-15% to abandonment expenditures. The capital expenditure budget and the allocation of capital across the various areas is subject to change based on several factors, including commodity pricing, liquidity, permitting times, regulatory, non-operator decisions and potential sales of working interests in certain assets.

Known Trends and Uncertainties.

Declining Commodity Prices – We experienced significant declines in oil, natural gas and NGL prices during the second half of 2014, with lower prices continuing throughout 2015 and into 2016, which resulted in reduced revenue and cash flows and caused us to reduce our planned capital expenditures for 2015 and 2016. Additionally, the low commodity prices have adversely affected the estimated value and quantities of our proved oil, natural gas and NGL reserves, which contributed to ceiling test write-downs of our oil and gas properties in 2014 and 2015. For the years ended December 31, 2014 and 2015, we recognized ceiling test write-downs of our oil and gas properties of $351 million (pre-tax) and $1,362 million (pre-tax), respectively. If NYMEX commodity prices remain at current levels (approximately $30 per Bbl of oil and $2.00 per MMBtu of natural gas), we would reasonably expect to incur further downward revisions of our estimated proved reserve quantities between 3 and 6 MMBoe (18 - 36 Bcfe) and would expect to recognize an additional ceiling test write-down between $100 and $200 million (pre-tax) in the first quarter of 2016.

Bank Credit Facility – We were in compliance with all of our financial covenants under our bank credit facility and the indentures governing our outstanding notes as of December 31, 2015. 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. 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. Additionally, the significant decline in commodity prices has materially adversely impacted the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. Continued low commodity prices or further declines in commodity prices will likely have a further material adverse impact on the estimated value and quantities of our proved reserves and we expect will likely result in a reduction of our borrowing base under our bank credit facility.

Realizability of Deferred Tax Assets – As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred during the fourth quarter of 2014 and during 2015, we determined that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a valuation allowance against a portion of our deferred tax assets, totaling $180.1 million at December 31, 2015. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities. As a result of an additional ceiling test write-down expected in the first quarter of 2016, we expect the valuation allowance to increase in the first quarter of 2016.

BOEM Bonding Requirements – The BOEM requires all operators in federal waters to provide financial assurances to cover the cost of plugging and abandoning wells and decommissioning offshore facilities. Historically, we and many other operators have been able to obtain an exemption from most bonding obligations based on financial net worth. However, in September 2015, the BOEM issued draft guidance (the “Draft Guidance”) describing revised financial assurance requirements that the agency intends to begin imposing in 2016. 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

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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.

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

Deep Water Operations – We are currently operating two significant properties in the deep water of the GOM. Additionally, we are engaged in deep water drilling operations. Operations in the deep water can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant losses on our statement of operations as well as going concern issues.

Appalachia Production Shut-ins – Production from our Mary field in Appalachia has been shut-in since September 2015, curtailing approximately 100 MMcfe of production per day, leaving approximately 21 MMcfe per day producing from our Heather and Buddy fields in Appalachia. Low commodity pricing, including negative price differentials in the area, combined with transportation, processing and gathering fees, have kept the operating margins at an unacceptable level. If operating margins do not return to acceptable levels, production may remain shut-in, affecting our future operating results, future development plans and hindering our ability to maintain leases.

Liquidity and Capital Resources

As of February 22, 2016, we had cash on hand of approximately $23 million and we had $50 million of outstanding borrowings and $19.2 million of outstanding letters of credit under the bank credit facility, leaving $430.8 million of availability under our bank credit facility. Our capital expenditure budget for 2016 has been set by the board of directors at $200 million, which assumes success in farming out the ENSCO 8503 deep water drilling rig to other operators for five to six months and the reduction in our working interests to acceptable levels on potential exploration wells to be drilled or stacking the rig. In addition to the $200 million in budgeted capital expenditures, the farm-out subsidies and rig stacking expenses would be charges to our statement of operations as "Other operational expenses" and could range between $40 and $50 million. The 2016 capital expenditure budget excludes material acquisitions and capitalized SG&A and interest as well as potential subsidy expense associated with rig farm-outs and rig stacking charges.

Based on our current outlook of commodity prices and our estimated production for 2016, we expect to fund our 2016 capital expenditures primarily through the bank credit facility and expected cash flows from operating activities, as well as possible financings or asset sales. If we fall out of compliance with the covenants set forth in our bank credit facility at the end of the first quarter of 2016 and are unable to reach an agreement with our banks, find acceptable alternative financing or complete asset sales, then we may need to adjust our capital expenditure budget. In order to address the March 2017 maturity of our 2017 Convertible Notes, we continue to analyze a variety of financing options, including a restructuring with current holders of the 2017 Convertible Notes (which may include exchanges of our 2017 Convertible Notes for new debt or equity securities), securing a secondary credit facility or second lien notes, utilizing the current credit facility, sale or joint venture of core or non-core assets, a sale and leaseback of owned infrastructure and issuance of debt or equity in the public or private markets. Such transactions, if any, will depend on prevailing market conditions, contractual restrictions and other factors, some of which may be outside of our control. Current market conditions may put limitations on our ability to issue new debt or equity securities in the public or private markets. 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 throughout 2015 and into 2016.

Although we are currently exempt from supplemental bonding requirements on our offshore leases for abandonment obligations, in 2016, we expect that we will not be able to qualify for a supplemental bonding waiver under the existing requirements imposed

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by the BOEM, as suppressed commodity prices have negatively affected our net worth. If we cannot qualify for a waiver, we may need to obtain surety bonds or some other form of financial assurance, which could impact our liquidity.

Cash Flow and Working Capital. Net cash provided by operating activities totaled $247.5 million during the year ended December 31, 2015 compared to $401.1 million and $594.2 million during the years ended December 31, 2014 and 2013, respectively. The decrease from 2014 to 2015 was primarily due to the decline in oil, natural gas and NGL prices, partially offset by a decline in lease operating expenses. The decrease from 2013 to 2014 was primarily due to reduced revenues as a result of the decline in oil prices and the divestiture of certain non-core GOM onshore and conventional shelf properties and an increase in transportation, processing and gathering expenses. See "Results of Operations" for additional information relative to commodity prices, production and operating expense variances.

Net cash used in investing activities totaled $321.3 million during the year ended December 31, 2015, which primarily represents our investment in oil and gas properties of $522.0 million, offset by $179.5 million of previously restricted proceeds from the sale of oil and gas properties and $22.8 million of proceeds from the sale of oil and gas properties. Net cash used in investing activities totaled $872.6 million during the year ended December 31, 2014, which primarily represents our investment in oil and gas properties of $927.2 million and our investment in fixed and other assets of $10.2 million, offset by unrestricted proceeds from the sale of oil and gas properties of $64.8 million. Net cash used in investing activities totaled $623.0 million during the year ended December 31, 2013, which primarily represents our investment in oil and gas properties of $663.3 million and our investment in fixed and other assets of $6.8 million, offset by proceeds from the sale of oil and gas properties of $48.8 million.

Net cash provided by financing activities totaled $10.2 million during the year ended December 31, 2015, which primarily represents $11.8 million of net proceeds from a 4.20% term loan (the "Building Loan"), offset by net payments for share-based compensation of approximately $3.1 million. During the year ended December 31, 2015, we had $5.0 million in borrowings and $5.0 million in repayments of borrowings under our bank credit facility. Net cash provided by financing activities totaled $215.4 million during the year ended December 31, 2014, which primarily represents net proceeds from the sale of common stock of approximately $226.0 million, offset by net payments for share-based compensation of approximately $7.2 million and deferred financing costs of approximately $3.4 million associated with our bank credit facility. Net cash provided by financing activities totaled $80.6 million for the year ended December 31, 2013, which primarily represents $480.2 million of net proceeds from the issuance of the 2022 Notes, less $396.0 million used for the redemption of our 8 5⁄8% Senior Notes due 2017 (the "2017 Senior Notes").

Although we had a working capital deficit of $8.8 million at December 31, 2015, we had $430.8 million of availability under our bank credit facility at February 22, 2016. However, continued low commodity prices or further declines in commodity prices will likely result in a reduction of our borrowing base at the time of our next redetermination by May 2016 (see Bank Credit Facility below).

Capital Expenditures. During the year ended December 31, 2015, additions to oil and gas property costs of $431.3 million included $7.6 million of lease and property acquisition costs, $27.1 million of capitalized SG&A expenses (inclusive of incentive compensation) and $41.3 million of capitalized interest. These investments were financed with cash on hand and cash flows from operating activities.

Bank Credit Facility. On June 24, 2014, we entered into an amended and restated revolving credit facility with commitments totaling $900 million (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019. On October 13, 2015, our borrowing base under the bank credit facility was reaffirmed at $500 million. As of February 22, 2016, we had $50 million of outstanding borrowings under the bank credit facility and $19.2 million in letters of credit had been issued pursuant to the bank credit facility, leaving $430.8 million of availability under the bank credit facility. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of December 31, 2015, the bank credit facility was guaranteed by Stone Energy Offshore, L.L.C., SEO A LLC and SEO B LLC.

The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated value of our oil and gas properties and those of our subsidiaries that guarantee the bank facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. Our borrowing base is scheduled to be redetermined by May 2016, and we expect that our borrowing base will be reduced as a result of that determination. 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 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

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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. While we expect a reduction in our borrowing base by May 2016, we do not expect a borrowing base deficiency at such time.

The bank credit facility is collateralized by substantially all of the assets of Stone and its material subsidiaries. We are required to mortgage and grant a security interest in our oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from our oil and natural gas reserves reviewed in determining the borrowing base. Low commodity prices and negative price differentials have had a material adverse impact on the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base. Continued low commodity prices or further declines in commodity prices will likely have a further material adverse impact on the value of our estimated proved reserves.

Interest on loans under the bank credit facility is calculated using the London Interbank Offering Rate (“LIBOR”) or the base rate, at the election of Stone. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%. Under the financial covenants of our bank credit facility, we must (1) maintain a ratio of Consolidated Funded Debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.75 to 1 and (2) maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 2.5 to 1. As of December 31, 2015, our Consolidated Funded Debt to consolidated EBITDA ratio was 3.09 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 7.91 to 1. In addition, our bank credit facility includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.

As 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.

Building Loan. On November 20, 2015, we entered into the Building Loan, maturing on December 20, 2030. We received $11.8 million in cash, net of debt issuance costs related to the Building Loan. The proceeds are being used for general corporate purposes. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments commencing on December 20, 2015. The Building Loan is collateralized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. As of December 31, 2015, our EBITDA to Net Interest Expense ratio was 7.91 to 1. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities.

Share Repurchase Program. On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under our share repurchase program. Through December 31, 2015, 300,000 shares had been repurchased under this program at a total cost of approximately $7.1 million, or an average price of $23.57 per share. No shares were repurchased during the years ended December 31, 2015, 2014 or 2013.

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

Safety Performance

Historically, we have measured our safety performance based on the total recordable incident rate (“TRIR”), which is the number of safety incidents per 200,000 man-hours worked for employees and certain contractors. For 2015, we broadened our safety performance measures, using a new factor called our Health, Safety and Environmental ("HSE") factor. The HSE factor includes not only personal safety as reflected by the TRIR, but also environmental safety, as measured by reported spills of hydrocarbons, and compliance safety, as measured by fines or penalties paid to state or federal regulatory agencies. All onshore safety incidents are reported to the Occupational Safety and Health Administration (“OSHA”) and are tracked on OSHA Form 301. All offshore safety incidents are reported to the BOEM. Our TRIR is provided to the BOEM as part of a voluntary program

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for safety monitoring in the GOM. The HSE factor for the year ended December 31, 2015 and the TRIR for the years ended December 31, 2014 and 2013 were as follows:



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

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

Results of Operations

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

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


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


(2)	Excludes incentive compensation expense.

Net Income. For the year ended December 31, 2015, we reported a net loss totaling $1,090.9 million, or $19.75 per share, compared to a net loss for the year ended December 31, 2014 of $189.5 million, or $3.60 per share. All per share amounts are on a diluted basis.

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

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

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

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2014 period. NGL production during the year ended December 31, 2015 totaled approximately 2,401 MBbls compared to 2,114 MBbls produced during the comparable 2014 period.

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

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

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

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

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

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

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

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

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

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

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

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

2014 Compared to 2013. The following table sets forth certain information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and natural gas reserves. See Item 2. Properties – Oil and Natural Gas Reserves.



	Year Ended December 31,
	2014		2013		Variance			% Change
Production:
Oil (MBbls)	5,568		6,894		(1,326		)	(19	)%
Natural gas (MMcf)	47,426		50,129		(2,703		)	(5	)%
NGLs (MBbls)	2,114		1,603		511			32	%
Oil, natural gas and NGLs (MMcfe)	93,518		101,111		(7,593		)	(8	)%
Revenue data (in thousands): (1)
Oil revenue	$	516,104	$	715,104	$	(199,000	)	(28	)%
Natural gas revenue	166,494		190,580		(24,086		)	(13	)%
NGL revenue	85,642		60,687		24,955			41	%
Total oil, natural gas and NGL revenue	$	768,240	$	966,371	$	(198,131	)	(21	)%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	91.27	$	103.22	$	(11.95	)	(12	)%
Natural gas (per Mcf)	3.67		3.47		0.20			6	%
NGLs (per Bbl)	40.51		37.86		2.65			7	%
Oil, natural gas and NGLs (per Mcfe)	8.21		9.36		(1.15		)	(12	)%
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	92.69	$	103.73	$	(11.04	)	(11	)%
Natural gas (per Mcf)	3.51		3.80		(0.29		)	(8	)%
NGLs (per Bbl)	40.51		37.86		2.65			7	%
Oil, natural gas and NGLs (per Mcfe)	8.21		9.56		(1.35		)	(14	)%
Expenses (per Mcfe):
Lease operating expenses	$	1.89	$	1.99	$	(0.10	)	(5	)%
Transportation, processing and gathering expenses	0.69		0.42		0.27			64	%
Salaries, general and administrative expenses (2)	0.71		0.59		0.12			20	%
DD&A expense on oil and gas properties	3.59		3.43		0.16			5	%
Estimated Proved Reserves at December 31:
Oil (MBbls)	42,397		43,827		(1,430		)	(3	)%
Natural gas (MMcf)	493,843		460,766		33,077			7	%
NGLs (MBbls)	27,817		23,297		4,520			19	%
Oil, natural gas and NGLs (MMcfe)	915,124		863,513		51,611			6	%


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


(2)	Excludes incentive compensation expense.

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Net Income. For the year ended December 31, 2014, we reported a net loss totaling $189.5 million, or $3.60 per share, compared to net income for the year ended December 31, 2013 of $117.6 million, or $2.36 per share. All per share amounts are on a diluted basis.

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

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

Production. During the year ended December 31, 2014, total production volumes decreased to 93.5 Bcfe compared to 101.1 Bcfe produced during the comparable 2013 period, representing an 8% decrease. The decrease in production was primarily attributable to the divestitures of certain non-core GOM onshore and conventional shelf properties, which represented approximately 13% and 24% of our total production volumes for the years ended December 31, 2014 and 2013, respectively. Oil production during the year ended December 31, 2014 totaled approximately 5,568 MBbls compared to 6,894 MBbls produced during the year ended December 31, 2013. Natural gas production totaled 47.4 Bcf during the year ended December 31, 2014 compared to 50.1 Bcf produced during the comparable 2013 period. NGL production during the year ended December 31, 2014 totaled approximately 2,114 MBbls compared to 1,603 MBbls produced during the comparable 2013 period.

Prices. Prices realized during the year ended December 31, 2014 averaged $92.69 per Bbl of oil, $3.51 per Mcf of natural gas and $40.51 per Bbl of NGLs, or 14% lower, on an Mcfe basis, than 2013 average realized prices of $103.73 per Bbl of oil, $3.80 per Mcf of natural gas and $37.86 per Bbl of NGLs. All unit pricing amounts include the cash settlement of effective hedging contracts.

We enter into various derivative contracts in order to reduce our exposure to the possibility of declining oil and natural gas prices. During the year ended December 31, 2014, effective hedging transactions decreased our average realized natural gas price by $0.16 per Mcf and increased our average realized oil price by $1.42 per Bbl. During the year ended December 31, 2013, effective hedging transactions increased our average realized natural gas price by $0.33 per Mcf and increased our average realized oil price by $0.51 per Bbl.

Revenue. Oil, natural gas and NGL revenue decreased 21% to $768.2 million for the year ended December 31, 2014 from $966.4 million for the year ended December 31, 2013. Total revenue for the year ended December 31, 2014 was lower partially due to the divestitures of certain non-core GOM onshore and conventional shelf properties. The decrease was also attributable to a 14% decrease in average realized prices.

Derivative Income/Expense. Net derivative income for the year ended December 31, 2014 totaled $19.4 million, comprised of $1.4 million of income from cash settlements and $18.0 million of non-cash income resulting from changes in the fair value of unsettled derivative instruments. For the year ended December 31, 2013, net derivative expense totaled $2.1 million, comprised primarily of non-cash fair value changes of unsettled derivative instruments.

Expenses. Lease operating expenses for the years ended December 31, 2014 and 2013 totaled $176.5 million and $201.2 million, respectively. On a unit of production basis, lease operating expenses were $1.89 per Mcfe and $1.99 per Mcfe for the years ended December 31, 2014 and 2013, respectively. The decrease in lease operating expenses in 2014 was primarily attributable to a decrease in major maintenance projects and the divestitures of certain of our non-core GOM onshore and conventional shelf properties.

Transportation, processing and gathering expenses for the years ended December 31, 2014 and 2013 totaled $65.0 million and $42.2 million, respectively, or $0.69 per Mcfe and $0.42 per Mcfe, respectively. The increase was attributable to higher natural gas, NGL and condensate volumes in Appalachia, where processing and gathering costs are higher.

DD&A expense on oil and gas properties for the year ended December 31, 2014 totaled $336.0 million, or $3.59 per Mcfe, compared to DD&A expense of $346.8 million, or $3.43 per Mcfe, for the year ended December 31, 2013. The increase in DD&A on a per unit basis was primarily attributable to the higher unit cost of reserve additions attributable to our GOM exploration program.

For the years ended December 31, 2014 and 2013, SG&A expenses (exclusive of incentive compensation) totaled $66.5 million and $59.5 million, respectively. The increase in SG&A expenses in 2014 was the result of increased legal fees, as well as increased staffing and salary adjustments. Included in SG&A expenses in 2013 was a reimbursement of $1.6 million of legal fees relating to the settlement of litigation in a prior period.

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For the years ended December 31, 2014 and 2013, incentive compensation expense totaled $10.4 million and $15.3 million, respectively. These amounts related to incentive compensation bonuses calculated based on the achievement of certain strategic objectives for each fiscal year.

Interest expense for the year ended December 31, 2014 totaled $38.9 million, net of $45.7 million of capitalized interest, compared to interest expense of $32.8 million, net of $46.9 million of capitalized interest, for the year ended December 31, 2013. The increase in interest expense was primarily the result of interest associated with the $475 million of 2022 Notes issued in November 2013. Partially offsetting this increase was a decrease in interest expense resulting from the redemption in November 2013 of our 2017 Senior Notes.

For the years ended December 31, 2014 and 2013, we recorded an income tax (benefit) provision of ($102.0) million and $68.7 million, respectively. The income tax benefit recorded in 2014 was a result of our loss before income taxes attributable to the ceiling test write-downs.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Contractual Obligations and Other Commitments

The following table summarizes our significant contractual obligations and commitments, other than derivative contracts, by maturity as of December 31, 2015 (in thousands):



	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Contractual Obligations and Commitments:
1 3⁄4% Senior Convertible Notes due 2017	$	300,000	$	—	$	300,000	$	—	$	—
7 1⁄2% Senior Notes due 2022	775,000		—		—		—		775,000
4.20% Building Loan	11,771		391		833		906		9,641
Interest and commitment fees (1)	426,305		65,695		123,454		118,006		119,150
Asset retirement obligations including accretion	741,111		20,840		202,478		18,785		499,008
Rig commitments (2)	149,242		89,505		59,737		—		—
Seismic data commitments	36,438		21,058		15,380		—		—
Operating lease obligations	4,462		2,022		1,421		906		113
Total Contractual Obligations and Commitments	$	2,444,329	$	199,511	$	703,303	$	138,603	$	1,402,912


(1)	Includes interest payable on the 2017 Convertible Notes, 2022 Notes and Building Loan. Assumes 0.375% 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.

Forward-Looking Statements

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

Accounting Matters and Critical Accounting Estimates

Fair Value Measurements. U.S. Generally Accepted Accounting Principles (“GAAP”), as codified, establish a framework for measuring fair value and require certain disclosures about fair value measurements. There is an established fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined

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as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

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

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

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

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

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

Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are calculated based on a trailing 12-month average pricing assumption.

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

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Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Our most significant estimates are:


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


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


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


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


•	effectiveness and estimated fair value of derivative positions;


•	classification of unevaluated property costs;


•	capitalized general and administrative costs and interest;


•	estimates of fair value in business combinations;


•	current and deferred income taxes; and


•	contingencies.

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

Recent Accounting Developments

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, “Revenue from Contracts with Customers” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 31, 2017. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

In August 2014, the FASB issued ASU 2014-15, "Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40)". The guidance will require management to evaluate whether there are conditions and events that raise substantial doubt about the company's ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Additionally, management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it plans to alleviate substantial doubt about the company's ability to continue as a going concern. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk. Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. For the year ended December 31, 2015, a 10% fluctuation in realized oil and natural gas prices, including the effects of hedging contracts, would have had an approximate $16.4 million impact on our revenues. Excluding the effects of hedging contracts, a 10% fluctuation in realized oil and natural gas prices would have had an approximate $38.2 million impact on our revenues. In order to manage our exposure to oil and natural gas price declines, we enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production.

We have entered into fixed-price swaps and costless collars with various counterparties for a portion of our expected 2016 oil and natural gas production from the Gulf Coast Basin. Our fixed-price oil swap settlements and oil collar settlements are based on an average of the NYMEX closing price for WTI crude oil during the entire calendar month. Our fixed-price gas swap settlements are based on the NYMEX price for the last day of a respective contract month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, The Bank of Nova Scotia and Natixis. Our oil collar contract is with The Bank of Nova Scotia.

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terms of such transactions. The counterparties to all of our derivative instruments have an "investment grade" credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At December 31, 2015, two counterparties accounted for approximately 86% of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility.

The following tables illustrate our hedging positions for calendar year 2016 as of February 22, 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

On October 15, 2015, our board of directors approved a change in the amount of our estimated production quantities that can be hedged for any given year, increasing it from 50% to 60%. We believe that our hedging positions as of February 22, 2016 have hedged approximately 28% of our estimated 2016 production from estimated proved reserves. Although we continue to monitor the marketplace for additional hedges for 2016 and beyond, continued weakness in commodity prices may impair our ability to secure hedges at prices we deem acceptable.

Interest Rate Risk. We had total debt outstanding of $1,087 million at December 31, 2015, all of which bears interest at fixed rates. The $1,087 million of fixed-rate debt is comprised of $300 million face value of the 2017 Convertible Notes, $775 million of the 2022 Notes and $12 million of the Building Loan.

Our bank credit facility is subject to an adjustable interest rate. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources. We had no outstanding borrowings under our bank credit facility as of December 31, 2015. If we borrow funds under our bank credit facility, we may be subject to increased sensitivity to interest rate movements. At February 22, 2016, we had $50 million of borrowings outstanding under our bank credit facility. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information concerning this Item begins on Page F-1.

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

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

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the

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end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2015 at the reasonable assurance level.

Changes in Internal Controls Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during the quarter ended December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined by the Exchange Act. Under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2015. In making this assessment, we used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (2013 framework). Based on our evaluation, we have concluded that our internal controls over financial reporting were effective as of December 31, 2015. Ernst and Young LLP, an independent public accounting firm, has issued its report on the company’s internal control over financial reporting as of December 31, 2015.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

We have audited Stone Energy Corporation’s internal control over financial reporting as of December 31, 2015, 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, 2015, 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 and 2014, 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, 2015 and our report dated February 26, 2016 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 26, 2016

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ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by Item 10 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2016 Annual Meeting of Stockholders to be held on May 19, 2016. The Company has made available free of charge on its Internet website (www.stoneenergy.com) the Code of Business Conduct and Ethics applicable to all employees of the Company, including the Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer. We will make timely disclosure on our website of any amendment to, or waiver from, the Code of Business Conduct and Ethics that applies to our principal executive and senior financial officers as required by applicable law.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2016 Annual Meeting of Stockholders to be held on May 19, 2016.

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

The information required by Item 12 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2016 Annual Meeting of Stockholders to be held on May 19, 2016.

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

The information required by Item 13 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2016 Annual Meeting of Stockholders to be held on May 19, 2016.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by Item 14 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2016 Annual Meeting of Stockholders to be held on May 19, 2016.

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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, 2015 and 2014

Consolidated Statement of Operations for the three years ended December 31, 2015, 2014 and 2013

Consolidated Statement of Comprehensive Income (Loss) for the three years ended December 31, 2015, 2014 and 2013

Consolidated Statement of Cash Flows for the three years ended December 31, 2015, 2014 and 2013

Consolidated Statement of Changes in Stockholders’ Equity for the three years ended December 31, 2015, 2014 and 2013

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:



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)).

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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).

†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)).

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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.

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*31.1	Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

*31.2	Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

*#32.1	Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.

*99.1	Report of Netherland, Sewell & Associates, Inc.

*101.INS	XBRL Instance Document

*101.SCH	XBRL Taxonomy Extension Schema Document

*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

*101.LAB	XBRL Taxonomy Extension Label Linkbase Document

*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

_________________



*	Filed or furnished herewith.
#	Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
†	Identifies management contracts and compensatory plans or arrangements.

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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 26, 2016		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 26, 2016
David H. Welch		February 26, 2016

/s/ Kenneth H. Beer	Executive Vice President and Chief Financial Officer (principal financial officer)	February 26, 2016
Kenneth H. Beer		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. 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

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INDEX TO FINANCIAL STATEMENTS



Report of Independent Registered Public Accounting Firm	F-2

Consolidated Balance Sheet as December 31, 2015 and 2014	F-3

Consolidated Statement of Operations for the years ended December 31, 2015, 2014 and 2013	F-4

Consolidated Statement of Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013	F-5

Consolidated Statement 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 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, 2015 and 2014, 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, 2015. 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 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, 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 2 to the financial statements, the Company could exceed the Consolidated Funded Debt to consolidated EBITDA financial ratio covenant set forth in its bank credit facility at the end of the first quarter of 2016, which would require the Company to seek a waiver or amendment from its bank lenders. 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. 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, 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 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 26, 2016

F-2

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STONE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands of dollars)



	December 31,
Assets	2015			2014
Current assets:
Cash and cash equivalents	$	10,759		$	74,488
Restricted cash	—			177,647
Accounts receivable	48,031			120,359
Fair value of derivative contracts	38,576			139,179
Current income tax receivable	46,174			7,212
Inventory	535			3,709
Other current assets	6,346			8,118
Total current assets	150,421			530,712
Oil and gas properties, full cost method of accounting:
Proved	9,375,898			8,817,268
Less: accumulated depreciation, depletion and amortization	(8,603,955		)	(6,970,631		)
Net proved oil and gas properties	771,943			1,846,637
Unevaluated	440,043			567,365
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
Total assets	$	1,410,169		$	3,009,857
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	82,207		$	132,629
Undistributed oil and gas proceeds	5,992			23,232
Accrued interest	9,022			9,022
Deferred taxes	—			20,119
Asset retirement obligations	21,291			69,400
Other current liabilities	40,712			49,505
Total current liabilities	159,224			303,907
Long-term debt	1,060,955			1,032,281
Deferred taxes	—			286,343
Asset retirement obligations	204,575			247,009
Other long-term liabilities	25,204			38,714
Total liabilities	1,449,958			1,908,254
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		)
Additional paid-in capital	1,648,189			1,633,307
Accumulated deficit	(1,705,623		)	(614,708		)
Accumulated other comprehensive income	17,952			83,315
Total stockholders’ equity	(39,789		)	1,101,603
Total liabilities and stockholders’ equity	$	1,410,169		$	3,009,857

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

F-3

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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)



	Year Ended December 31,
	2015			2014			2013
Operating revenue:
Oil production	$	416,497		$	516,104		$	715,104
Natural gas production	83,509			166,494			190,580
Natural gas liquids production	32,322			85,642			60,687
Other operational income	4,369			7,951			7,808
Derivative income, net	7,952			19,351			—
Total operating revenue	544,649			795,542			974,179
Operating expenses:
Lease operating expenses	100,139			176,495			201,153
Transportation, processing and gathering expenses	58,847			64,951			42,172
Production taxes	6,877			12,151			15,029
Depreciation, depletion and amortization	281,688			340,006			350,574
Write-down of oil and gas properties	1,362,447			351,192			—
Accretion expense	25,988			28,411			33,575
Salaries, general and administrative expenses	69,384			66,451			59,524
Franchise tax settlement	—			—			12,590
Incentive compensation expense	2,242			10,361			15,340
Other operational expenses	2,360			862			151
Derivative expense, net	—			—			2,090
Total operating expenses	1,909,972			1,050,880			732,198
Income (loss) from operations	(1,365,323		)	(255,338		)	241,981
Other (income) expenses:
Interest expense	43,928			38,855			32,837
Interest income	(580		)	(574		)	(1,695		)
Other income	(1,783		)	(2,332		)	(2,799		)
Other expense	434			274			—
Loss on early extinguishment of debt	—			—			27,279
Total other expenses	41,999			36,223			55,622
Income (loss) before income taxes	(1,407,322		)	(291,561		)	186,359
Provision (benefit) for income taxes:
Current	(44,096		)	159			(10,904		)
Deferred	(272,311		)	(102,177		)	79,629
Total income taxes	(316,407		)	(102,018		)	68,725
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
Average shares outstanding	55,250			52,721			48,693
Average shares outstanding assuming dilution	55,250			52,721			48,735

The accompanying notes are an integral part of this statement.

F-4

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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)



	Year Ended December 31,
	2015			2014			2013
Net income (loss)	$	(1,090,915	)	$	(189,543	)	$	117,634
Other comprehensive income (loss), net of tax effect:
Derivatives	(62,758		)	88,178			(30,228		)
Foreign currency translation	(2,605		)	(2,801		)	(667		)
Comprehensive income (loss)	$	(1,156,278	)	$	(104,166	)	$	86,739

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)



	Year Ended December 31,
	2015			2014			2013
Cash flows from operating activities:
Net income (loss)	$	(1,090,915	)	$	(189,543	)	$	117,634
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	281,688			340,006			350,574
Write-down of oil and gas properties	1,362,447			351,192			—
Accretion expense	25,988			28,411			33,575
Deferred income tax (benefit) provision	(272,311		)	(102,177		)	79,629
Settlement of asset retirement obligations	(72,382		)	(56,409		)	(83,854		)
Non-cash stock compensation expense	12,324			11,325			10,347
Excess tax benefits	(1,586		)	—			(156		)
Non-cash derivative (income) expense	16,440			(18,028		)	2,239
Loss on early extinguishment of debt	—			—			27,279
Non-cash interest expense	17,788			16,661			16,219
Change in current income taxes	(37,377		)	158			2,767
(Increase) decrease in accounts receivable	43,724			51,611			(4,683		)
(Increase) decrease in other current assets	1,767			(6,244		)	1,752
Decrease in inventory	1,304			—			583
Increase (decrease) in accounts payable	(14,582		)	(3,419		)	402
Increase (decrease) in other current liabilities	(25,936		)	(19,152		)	42,451
Other	(907		)	(3,251		)	(2,553		)
Net cash provided by operating activities	247,474			401,141			594,205
Cash flows from investing activities:
Investment in oil and gas properties	(522,047		)	(927,247		)	(663,299		)
Proceeds from sale of oil and gas properties, net of expenses	22,839			242,914			48,821
Investment in fixed and other assets	(1,549		)	(10,182		)	(6,816		)
Change in restricted funds	179,467			(178,072		)	(1,742		)
Net cash used in investing activities	(321,290		)	(872,587		)	(623,036		)
Cash flows from financing activities:
Proceeds from bank borrowings	5,000			—			—
Repayments of bank borrowings	(5,000		)	—			—
Proceeds from building loan	11,770			—			—
Proceeds from issuance of senior notes	—			—			489,250
Net proceeds from issuance of common stock	—			225,999			—
Deferred financing costs	(68		)	(3,371		)	(9,065		)
Redemption of senior notes	—			—			(396,014		)
Excess tax benefits	1,586			—			156
Net payments for share-based compensation	(3,127		)	(7,182		)	(3,733		)
Net cash provided by financing activities	10,161			215,446			80,594
Effect of exchange rate changes on cash	(74		)	(736		)	(65		)
Net change in cash and cash equivalents	(63,729		)	(256,736		)	51,698
Cash and cash equivalents, beginning of year	74,488			331,224			279,526
Cash and cash equivalents, end of year	$	10,759		$	74,488		$	331,224
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	$	(34,394	)	$	(14,076	)	$	(29,883	)
Cash (paid) refunded for income taxes	7,212			(1		)	13,670

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)



	Common Stock		Treasury Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance, December 31, 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
Net loss	—		—			—			(189,543		)	—			(189,543		)
Adjustment for fair value accounting of derivatives, net of tax	—		—			—			—			88,178			88,178
Adjustment for foreign currency translation, net of tax	—		—			—			—			(2,801		)	(2,801		)
Exercise of stock options and vesting of restricted stock	3		—			(7,174		)	—			—			(7,171		)
Amortization of stock compensation expense	—		—			16,709			—			—			16,709
Net tax impact from stock option exercises and restricted stock vesting	—		—			(54		)	—			—			(54		)
Issuance of common stock	58		—			225,941			—			—			225,999
Balance, December 31, 2014	549		(860		)	1,633,307			(614,708		)	83,315			1,101,603
Net loss	—		—			—			(1,090,915		)	—			(1,090,915		)
Adjustment for fair value accounting of derivatives, net of tax	—		—			—			—			(62,758		)	(62,758		)
Adjustment for foreign currency translation, net of tax	—		—			—			—			(2,605		)	(2,605		)
Exercise of stock options and vesting of restricted stock	4		—			(2,642		)	—			—			(2,638		)
Amortization of stock compensation expense	—		—			17,524			—			—			17,524
Balance, December 31, 2015	$	553	$	(860	)	$	1,648,189		$	(1,705,623	)	$	17,952		$	(39,789	)

The accompanying notes are an integral part of this statement.

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STONE ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In thousands of dollars, except per share and price amounts)

NOTE 1 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Stone Energy Corporation (“Stone”) is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We began operating in the Gulf of Mexico (the “GOM”) Basin in 1993 and have established a technical and operational expertise in this area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus and Utica shales in Appalachia. 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.

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

Basis of Presentation:

The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Energy Offshore, L.L.C. (“Stone Offshore”), Stone Energy Holding, L.L.C., Stone Energy Canada, U.L.C., SEO A LLC and SEO B LLC. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation (see Note 11 - Long-Term Debt).

Use of Estimates:

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization (“DD&A”) expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, income taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative contracts, estimates of fair value in business combinations and contingencies.

Fair Value Measurements:

U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2015 and 2014, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.

Hybrid Debt Instruments:

In 2012, we issued $300,000 in aggregate principal amount of 1 3⁄4% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”). See Note 11 – Long-Term Debt. On that same day we entered into convertible note hedging transactions which are expected to reduce the potential dilution to our common shareholders upon conversion of the notes. In accordance with Accounting Standards Codification (“ASC”) 480-20 and ASC 470, we accounted for the debt and equity portions of the notes in a manner that will reflect our nonconvertible borrowing rate when interest is recognized in subsequent periods. This results in the separation of the debt component, classification of the remaining component in stockholders’ equity, and accretion of the resulting discount as interest expense. Additionally, the hedging transactions meet the criteria for classification as equity transactions and were recorded as such.

Cash and Cash Equivalents:

We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents.

Oil and Gas Properties:

We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any

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

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

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

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

Asset Retirement Obligations:

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

Other Property and Equipment:

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

Inventory:

We maintain an inventory of tubular goods. Items remain in inventory until dedicated to specific projects, at which time they are transferred to oil and gas properties. Items are carried at the lower of cost or market based on the specific identification method.

Earnings Per Common Share:

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

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Production Revenue:

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

Income Taxes:

Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment relative to successful wells are capitalized and recovered through DD&A, although for 2013, 2014 and 2015, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation.

Derivative Instruments and Hedging Activities:

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

Share-Based Compensation:

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

NOTE 2 — GOING CONCERN:

The accompanying consolidated financial statements have been prepared assuming the company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of liabilities that may result should the company be unable to continue as a going concern.

The level of our indebtedness of $1,137,000 and the current commodity price environment have presented challenges as they relate to our ability to comply with the covenants in the agreements governing our indebtedness. At 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 ratio covenant of 3.75 to 1 set forth in our bank credit agreement at the end of the first quarter of 2016, which would require us to seek a waiver or amendment from our bank lenders. 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. These conditions raise substantial doubt about our ability to continue as a going concern.

We are currently in discussions with our banks regarding an amendment to our bank credit facility to address this potential covenant issue. We cannot provide any assurances that we will reach an agreement with the lenders under our bank credit facility on a waiver or amendment on a timely basis, or on satisfactory terms, to alleviate any non-compliance with our debt covenants. Additionally, we have $1,075,000 of senior indebtedness that we need to restructure or pay down. We are in the process of analyzing

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various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, asset sales and a prepackaged bankruptcy filing. We cannot provide any assurances that we will be able to complete a private restructuring or asset sales on satisfactory terms to provide the liquidity to restructure or pay down our senior indebtedness.

NOTE 3 — EARNINGS PER SHARE:

The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods:



	Year Ended December 31,
	2015			2014			2013
Income (numerator):
Basic:
Net income (loss)	$	(1,090,915	)	$	(189,543	)	$	117,634
Net income attributable to participating securities	—			—			(2,817		)
Net income (loss) attributable to common stock - basic	$	(1,090,915	)	$	(189,543	)	$	114,817
Diluted:
Net income (loss)	$	(1,090,915	)	$	(189,543	)	$	117,634
Net income attributable to participating securities	—			—			(2,815		)
Net income (loss) attributable to common stock - diluted	$	(1,090,915	)	$	(189,543	)	$	114,819
Weighted average shares (denominator):
Weighted average shares - basic	55,250			52,721			48,693
Dilutive effect of stock options	—			—			42
Weighted average shares - diluted	55,250			52,721			48,735
Basic earnings (loss) per share	$	(19.75	)	$	(3.60	)	$	2.36
Diluted earnings (loss) per share	$	(19.75	)	$	(3.60	)	$	2.36

All outstanding stock options were considered antidilutive during the years ended December 31, 2015 (145,000 shares) and December 31, 2014 (205,000 shares) because we had a net loss for such periods. Stock options that were considered antidilutive because the exercise price of the options exceeded the average price of our common stock for the applicable period totaled approximately 242,000 shares during the year ended December 31, 2013.

During the years ended December 31, 2015, 2014 and 2013, approximately 418,000, 384,000 and 358,000 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock and the exercise of stock options by employees and nonemployee directors. In May 2014, 5,750,000 shares of our common stock were issued in a public offering.

For the years ended December 31, 2015 and 2014, the 2017 Convertible Notes had no dilutive effect in the diluted earnings per share computation as we had a net loss for such years. For the year ended December 31, 2013, the average price of our common stock was less than the effective conversion price for such notes, resulting in no dilutive effect in the diluted earnings per share computation under the treasury stock method. For the years ended December 31, 2015, 2014 and 2013, the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 11 – Long-Term Debt) and therefore, such warrants were not dilutive for such years. Based on the terms of the Purchased Call Options (as defined in Note 11 – Long-Term Debt), such call options are antidilutive and therefore, were not included in the calculation of diluted earnings per share.

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NOTE 4 — ACCOUNTS RECEIVABLE:

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



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

NOTE 5 — CONCENTRATIONS:

Sales to Major Customers

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



	Year Ended December 31,
	2015		2014		2013
Phillips 66 Company	53	%	31	%	35	%
Shell Trading (US) Company	13	%	32	%	33	%

The maximum amount of credit risk exposure at December 31, 2015 relating to these customers was $20,826.

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

Production and Reserve Volumes- Unaudited

Approximately 99% of our estimated proved reserves at December 31, 2015 and 56% of our production during 2015 were associated with our GOM deep water, conventional shelf and deep gas properties. Approximately 1% of our estimated proved reserves at December 31, 2015 and 44% of our production during 2015 were associated with our Appalachian properties.

Cash and Cash Equivalents

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

NOTE 6 — DIVESTITURES:

On January 16, 2014, we completed the sale of our interests in the Cut Off and Clovelly fields (onshore Louisiana) for cash consideration at closing of approximately $44,804 and the assumption of the associated asset retirement obligations of approximately $9,162. On July 31, 2014, we completed the sale of certain non-core properties in the GOM conventional shelf for cash consideration at closing of approximately $177,647, after giving effect to preliminary purchase price adjustments and the assumption of the associated asset retirement obligations of approximately $125,198. Additionally, in 2014, we completed the sales of our interests in other non-core fields, including Katie (Pennsylvania), Hatch Point (Utah), Falls City (Texas) and South Marsh Island Block 192 (GOM), for a combined cash consideration of approximately $26,065 and the assumption of the associated asset retirement obligations of approximately $3,440. These sales were accounted for as reductions to net proved oil and gas properties, with total cash consideration and the assumed asset retirement obligation recorded as an increase to accumulated DD&A. No gain or loss was recognized since the adjustments did not significantly alter the relationship between capitalized costs and proved reserves.

All of the proceeds from the July 31, 2014 sale of certain of our non-core GOM conventional shelf properties were deposited with a Qualified Intermediary (under the terms of a Qualified Trust Agreement and Exchange Agreement) for potential reinvestment

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in like-kind replacement property as defined under Section 1031 of the Internal Revenue Code, and were included in our balance sheet as restricted cash at December 31, 2014. Compliance with provisions under the Qualified Trust Agreement and Exchange Agreement provided for deferral of taxable gain on these sales proceeds. We identified qualified replacement properties and had until January 27, 2015 to close on such properties in order to achieve deferral of our taxable gain. We did not close on such a transaction by January 27, 2015, and the funds were released from restrictions and reclassified to cash and cash equivalents at such date.

NOTE 7 — DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.

We have entered into fixed-price swaps and costless collars with various counterparties for a portion of our expected 2016 oil and natural gas production from the Gulf Coast Basin. Our fixed-price oil swap settlements and oil collar settlements are based on an average of the New York Mercantile Exchange (“NYMEX”) closing price for West Texas Intermediate crude oil during the entire calendar month. Our fixed-price gas swap settlements are based on the NYMEX price for the last day of a respective contract month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Collar contracts typically require payments by us if the NYMEX average closing price is above the ceiling price or payments to us if the NYMEX average closing price is below the floor price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, The Bank of Nova Scotia and Natixis. Our oil collar contract is with The Bank of Nova Scotia.

All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative instruments involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties to all of our derivative instruments have an "investment grade" credit rating. We monitor the credit ratings of our derivative counterparties on an ongoing basis. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, we may not realize the benefit of some of our derivative instruments and incur a loss. At December 31, 2015, two counterparties accounted for approximately 86% of our contracted volumes. All of our derivative instruments are with lenders under our bank credit facility.

The following tables illustrate our derivative positions for calendar year 2016 as of February 22, 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

All of our derivative instruments at December 31, 2013 were designated as effective cash flow hedges. During 2014, certain of our natural gas derivative instruments no longer qualified as cash flow hedges, as it was no longer probable, subsequent to the sale of our non-core GOM conventional shelf properties (see Note 6 – Divestitures), that GOM natural gas production would be sufficient to cover the GOM volumes hedged. Accordingly, we discontinued hedge accounting for certain contracts for the months of August through December 2014 and January through December 2015. Additionally, a small portion of our cash flow hedges are typically determined to be ineffective because oil and natural gas price changes in the markets in which we sell our products

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are not 100% correlative to changes in the underlying price basis indicative in the derivative contract. At December 31, 2015, we had accumulated other comprehensive income of $24,025, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of December 31, 2015.The $24,025 of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.

Derivatives qualifying as hedging instruments:

The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2015 and 2014:

Fair Value of Derivatives Qualifying as Hedging Instruments at

December 31, 2015

Asset Derivatives

Liability Derivatives

Description

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity contracts

Current assets: Fair value of derivative contracts

38,576

Current liabilities: Fair value of derivative contracts

—

Long-term assets: Fair value of derivative contracts

—

Long-term liabilities: Fair value of derivative contracts

—

38,576

—



Fair Value of Derivatives Qualifying as Hedging Instruments at
December 31, 2014
	Asset Derivatives			Liability Derivatives
Description	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	$	—
	Long-term assets: Fair value of derivative contracts	14,333		Long-term liabilities: Fair value of derivative contracts	—
		$	141,366		$	—

The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the years ended December 31, 2015, 2014 and 2013:



Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
for the Years Ended December 31, 2015, 2014, and 2013
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in Other Comprehensive Income on Derivatives			Gain (Loss) Reclassified from Accumulated Other Comprehensive Income into Income (Effective Portion) (a)			Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion)
				Location			Location
	2015				2015			2015
Commodity contracts	$	52,630		Operating revenue - oil/natural gas production	$	149,955	Derivative income (expense), net	$	2,713
Total	$	52,630			$	149,955		$	2,713

	2014				2014			2014
Commodity contracts	$	136,097		Operating revenue - oil/natural gas production	$	526	Derivative income (expense), net	$	5,721
Total	$	136,097			$	526		$	5,721

	2013				2013			2013
Commodity contracts	$	(26,945	)	Operating revenue - oil/natural gas production	$	20,289	Derivative income (expense), net	$	(2,090	)
Total	$	(26,945	)		$	20,289		$	(2,090	)

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(a)

For the year ended December 31, 2015, effective hedging contracts increased oil revenue by $135,617 and increased natural gas revenue by $14,338. For the year ended December 31, 2014, effective hedging contracts increased oil revenue by $7,929 and (decreased) natural gas revenue by $7,403. For the year ended December 31, 2013, effective hedging contracts increased oil revenue by $3,520 and increased natural gas revenue by $16,769.

Derivatives not qualifying as hedging instruments:

The following table discloses the location and fair value amounts of our derivatives not qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2015 and 2014:



Fair Value of Derivatives Not Qualifying as Hedging Instruments
Description	Balance Sheet Location	December 31, 2015		December 31, 2014
Commodity contracts	Current assets: Fair value of derivative contracts	$	—	$	12,146

Gains or losses related to changes in fair value and cash settlements for derivatives not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations for the years ended December 31, 2015 and 2014. All of our derivatives for the year ended December 31, 2013 qualified as hedging instruments.



Gain (Loss) Recognized in Derivative Income (Expense)
	Year Ended
Description	December 31, 2015			December 31, 2014
Commodity contracts:
Cash settlements	$	17,385		$	1,484
Change in fair value	(12,146		)	12,146
Total gain on non-qualifying derivatives	$	5,239		$	13,630

Offsetting of derivative assets and liabilities:

Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. As of December 31, 2015 and 2014, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset.

NOTE 8 – FAIR VALUE MEASUREMENTS:

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

As of December 31, 2015 and 2014, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy, and our collar contracts are included within the Level 3 fair value hierarchy. Significant unobservable inputs used in establishing fair value for the collars were the volatility impacts in the pricing model as it relates to the call portion of the collar. For a more detailed description of our derivative instruments, see Note 7 – Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.

We had no liabilities measured at fair value on a recurring basis at December 31, 2015 and 2014. The following tables present our assets that are measured at fair value on a recurring basis at December 31, 2015 and 2014:

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	Fair Value Measurements at
	December 31, 2015
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	8,499	$	8,499	$	—	$	—
Derivative contracts	38,576		—		36,603		1,973
Total	$	47,075	$	8,499	$	36,603	$	1,973



	Fair Value Measurements at
	December 31, 2014
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Marketable securities (Other assets)	$	8,425	$	8,425	$	—	$	—
Derivative contracts	153,512		—		153,512		—
Total	$	161,937	$	8,425	$	153,512	$	—

The table below presents a reconciliation for assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the year ended December 31, 2015.



	Hedging Contracts, net
Balance as of January 1, 2015	$	—
Total gains/(losses) (realized or unrealized):
Included in earnings	63
Included in other comprehensive income	1,910
Purchases, sales, issuances and settlements	—
Transfers in and out of Level 3	—
Balance as of December 31, 2015	$	1,973
The amount of total gains/(losses) for the period included in earnings (derivative income) attributable to the change in unrealized gain/(losses) relating to derivatives still held at December 31, 2015	$	63

The fair value of cash and cash equivalents approximated book value at December 31, 2015 and 2014. As of December 31, 2015 and 2014, the fair value of the liability component of the 2017 Convertible Notes was approximately $217,117 and $252,587, respectively. As of December 31, 2015 and 2014, the fair value of the 7 1⁄2% Senior Notes due 2022 (the “2022 Notes”) was approximately $271,250 and $664,563, respectively.

The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see Note 11 – Long-Term Debt) at inception and at December 31, 2015 and 2014. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

NOTE 9 — ASSET RETIREMENT OBLIGATIONS:

The change in our asset retirement obligations during the years ended December 31, 2015, 2014 and 2013 is set forth below:

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	Year Ended December 31,
	2015			2014			2013
Asset retirement obligations as of the beginning of the year, including current portion	$	316,409		$	502,513		$	488,302
Liabilities incurred	15,933			28,606			19,043
Liabilities settled	(72,713		)	(55,839		)	(79,695		)
Divestment of properties	(248		)	(137,801		)	(9,245		)
Accretion expense	25,988			28,411			33,575
Revision of estimates	(59,503		)	(49,481		)	50,533
Asset retirement obligations as of the end of the year, including current portion	$	225,866		$	316,409		$	502,513

NOTE 10 — INCOME TAXES:

An analysis of our deferred taxes follows:



	As of December 31,
	2015			2014
Tax effect of temporary differences:
Net operating loss carryforwards	$	31,624		$	99,615
Oil and gas properties – full cost	76,766			(476,367		)
Asset retirement obligations	79,618			113,907
Stock compensation	5,199			5,603
Hedges	(13,598		)	(54,439		)
Accrued incentive compensation	1,234			6,185
Other	(722		)	(966		)
Total deferred tax assets (liabilities)	180,121			(306,462		)
Valuation allowance	(180,121		)	—
Net deferred tax liabilities	$	—		$	(306,462	)

We estimate that we had ($44,096), $159 and ($10,904) of current federal income tax expense (benefit) for the years ended December 31, 2015, 2014 and 2013, respectively. For the years ended December 31, 2015, 2014 and 2013, we recorded deferred income tax expense (benefits) of ($272,311), ($102,177) and $79,629, respectively. The deferred income tax benefits were a result of our losses before income taxes attributable primarily to ceiling test write-downs of our oil and gas properties (see Note 17 - Supplemental Information on Oil and Natural Gas Operations - Unaudited). We had current income tax receivables of $46,174 and $7,212 at December 31, 2015 and 2014, respectively, both of which were expected tax refunds from the carryback of net operating losses to previous tax years.

For tax reporting purposes, net operating loss carryforwards totaled approximately $97,225 at December 31, 2015. If not utilized, the majority of such carryforwards would expire in 2035. In addition, we had approximately $1,056 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these and other carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized. As a result of the significant declines in commodity prices and the resulting ceiling test write-downs and net losses incurred over the past several quarters, we determined during 2015 that it was more likely than not that a portion of our deferred tax assets will not be realized in the future. Accordingly, we established a $180,121 valuation allowance against a portion of our deferred tax assets. Our assessment of the realizability of our deferred tax assets is based on the weight of all available evidence, both positive and negative, including future reversals of deferred tax liabilities.

A reconciliation between the statutory federal income tax rate and our effective income tax rate as a percentage of income before income taxes follows:

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	Year Ended December 31,
	2015	2014	2013
Income tax expense computed at the statutory federal income tax rate	35.0%	35.0%	35.0%
State taxes	0.6	1.0	1.0
Change in valuation allowance	(12.8)	—	—
IRC Sec. 162(m) limitation	(0.1)	(0.5)	0.8
Tax deficits on stock compensation	(0.1)	(0.2)	—
Other	(0.1)	(0.3)	0.1
Effective income tax rate	22.5%	35.0%	36.9%

Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to ($35,737), $49,601 and ($17,003) for the years ended December 31, 2015, 2014 and 2013, respectively.

As of December 31, 2015, we had unrecognized tax benefits of $491. If recognized, all of our unrecognized tax benefits would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows:



Total unrecognized tax benefits as of December 31, 2014	$	—
Increases (decreases) in unrecognized tax benefits as a result of:
Tax positions taken during a prior period	491
Tax positions taken during the current period	—
Settlements with taxing authorities	—
Lapse of applicable statute of limitations	—
Total unrecognized tax benefits as of December 31, 2015	$	491

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

It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. We recognized $131 of interest expense and no penalties related to uncertain tax positions for the year ended December 31, 2015. No such amounts were recognized for the year ended December 31, 2014. The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet.

The tax years 2012 through 2015 remain subject to examination by major tax jurisdictions.

NOTE 11 — LONG-TERM DEBT:

Long-term debt consisted of the following at:



	December 31,
	2015		2014
1 3⁄4% Senior Convertible Notes due 2017	$	279,244	$	262,791
7 1⁄2% Senior Notes due 2022	770,009		769,490
Revolving credit facility	—		—
4.20% Building Loan	11,702		—
Total long-term debt	$	1,060,955	$	1,032,281

Revolving Credit Facility

On June 24, 2014, we entered into an amended and restated revolving credit facility with commitments totaling $900,000 (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019. Our initial borrowing base under the bank credit facility was set at $500,000 and was reaffirmed at $500,000 in October 2015. As of December 31, 2015, we had no outstanding borrowings under the bank credit facility and $19,221 in letters of credit had been issued pursuant to the bank credit facility, leaving $480,779 of availability under the bank credit facility.

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As of February 22, 2016, we had $50,000 of outstanding borrowings under the bank credit facility and $19,221 in letters of credit had been issued pursuant to the bank credit facility, leaving $430,779 of availability under the bank credit facility. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. As of December 31, 2015, the bank credit facility was guaranteed by Stone Offshore, SEO A LLC and SEO B LLC (collectively, the "Guarantor Subsidiaries").

The borrowing base under the bank credit facility is redetermined semi-annually, typically in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank credit facility in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. If, due to a redetermination of our borrowing base, our outstanding bank credit facility borrowings plus any 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 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 deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so; and/or (3) arrange to pay the deficiency in six equal monthly installments.

The bank credit facility is collateralized by substantially all of the assets of Stone and its material subsidiaries. We are required to mortgage, and grant a security interest in, our oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from our proved oil and natural gas reserves reviewed in determining the borrowing base. Interest on loans under the bank credit facility is calculated using the London Interbank Offering (“LIBOR”) rate or the base rate, at the election of Stone. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%.

Under the financial covenants of the bank credit facility, we must (1) maintain a ratio of Consolidated Funded Debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.75 to 1 and (2) maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 2.5 to 1. As of December 31, 2015, our Consolidated Funded Debt to consolidated EBITDA ratio was 3.09 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 7.91 to 1. In addition, our bank credit facility includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of control and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of December 31, 2015.

Building Loan

On November 20, 2015, we entered into an $11,802 term loan agreement (the "Building Loan"), maturing on December 20, 2030. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of $73 commencing on December 20, 2015. The Building Loan is collaterized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. As of December 31, 2015, our EBITDA to Net Interest Expense ratio was 7.91 to 1. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities.

2017 Convertible Notes

On March 6, 2012, we issued in a private offering $300,000 in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes are convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, based on an initial conversion rate of 2.3445 shares of our common stock per $1 principal amount of 2017 Convertible Notes, which corresponds to an initial conversion price of approximately $42.65 per share of our common stock. On December 31, 2015, our closing share price was $4.29. The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture related to the 2017 Convertible Notes.

The 2017 Convertible Notes may be converted by the holder, in multiples of $1 principal amount, only under the following circumstances:


•	prior to December 1, 2016, on any date during any calendar quarter beginning after June 30, 2012 (and only during such calendar quarter) if the closing sale price of our common stock was more than 130% of the then current conversion

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price for at least 20 trading days in the period of the 30 consecutive trading days ending on the last trading day of the previous calendar quarter;

•

prior to December 1, 2016, if we distribute to all or substantially all holders of our common stock rights, options or warrants entitling them to purchase, for a period of 45 calendar days or less from the declaration date for such distribution, shares of our common stock at a price per share less than the average closing sale price of our common stock for the 10 consecutive trading days immediately preceding, but excluding, the declaration date for such distribution;

•

prior to December 1, 2016, if we distribute to all or substantially all holders of our common stock cash, other assets, securities or rights to purchase our securities, which distribution has a per share value exceeding 10% of the closing sale price of our common stock on the trading day immediately preceding the declaration date for such distribution, or if we engage in certain corporate transactions described in the indenture related to the 2017 Convertible Notes;

•

prior to December 1, 2016, during the five consecutive business-day period following any five consecutive trading-day period in which the trading price per $1 principal amount of 2017 Convertible Notes for each trading day during such five trading-day period was less than 98% of the closing sale price of our common stock for each trading day during such five trading-day period multiplied by the then current conversion rate; or


•	on or after December 1, 2016, and prior to the close of business on the second scheduled trading day immediately preceding the maturity date of the 2017 Convertible Notes, which is March 1, 2017, without regard to the foregoing conditions.

Upon conversion, we will be obligated to pay or deliver, as the case may be, cash, shares of our common stock or a combination of cash and shares of our common stock. If we satisfy our conversion obligation solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of our common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture related to the 2017 Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture related to the 2017 Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 2017 Convertible Notes will not receive any cash payment representing accrued and unpaid interest. Instead, interest will be deemed to be paid by the cash, shares of our common stock or a combination of cash and shares of our common stock paid or delivered, as the case may be, upon conversion of a 2017 Convertible Note.

The 2017 Convertible Notes will be due on March 1, 2017, unless earlier converted or repurchased by us at the option of the holder(s), and interest is payable on the 2017 Convertible Notes each March 1 and September 1. On the maturity date, each holder will be entitled to receive $1 in cash for each $1 in principal amount of 2017 Convertible Notes, together with any accrued and unpaid interest to, but excluding, the maturity date.

In connection with the offering, we entered into convertible note hedge transactions with respect to our common stock (the “Purchased Call Options”) with Barclays Capital Inc., acting as agent for Barclays Bank PLC and Bank of America, N.A. (the “Dealers”). We paid an aggregate amount of approximately $70,830 to the Dealers for the Purchased Call Options. The Purchased Call Options cover, subject to customary antidilution adjustments, approximately 7,033,470 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes, also subject to adjustment, and are exercisable upon conversion of the 2017 Convertible Notes.

We also entered into separate warrant transactions whereby, in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately 7,033,470 shares of our common stock (the “Sold Warrants”) at a strike price of $55.91 per share of our common stock. We received aggregate proceeds of approximately $40,170 from the sale of the Sold Warrants to the Dealers. If, upon expiration of the Sold Warrants, the price per share of our common stock, as measured under the Sold Warrants, is greater than the strike price of the Sold Warrants, we will be required to issue, without further consideration, under each Sold Warrant a number of shares of our common stock with a value equal to the amount of such difference.

As of December 31, 2015, the carrying amount of the liability component of the 2017 Convertible Notes was $279,244 and $1,750 had been accrued in connection with the March 1, 2016 interest payment. During the year ended December 31, 2015, we recognized $15,019 of interest expense for the amortization of the discount and $1,434 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2014, we recognized $13,951 of interest expense for the amortization of the discount and $1,332 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2013, we recognized $12,599 of interest expense for the amortization of the discount and $1,238 of interest expense for the amortization of deferred financing costs related to the

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2017 Convertible Notes. During each of the years ended December 31, 2015, 2014 and 2013, we recognized $5,250 of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.

2022 Notes

On November 8, 2012, we completed the public offering of $300,000 aggregate principal amount of our 2022 Notes, which are fully and unconditionally guaranteed on a senior unsecured basis by Stone Offshore, SEO A LLC, SEO B LLC and by certain future restricted subsidiaries of Stone. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $293,203. On November 27, 2013, we completed the public offering of an additional $475,000 aggregate principal amount of our 2022 Notes at a 3% premium. The net proceeds from this offering after deducting underwriting discounts, commissions, fees and expenses totaled $480,195. The 2022 Notes rank equally in right of payment with all of our existing and future senior debt, and rank senior in right of payment to all of our existing and future subordinated debt. The 2022 Notes mature on November 15, 2022, and interest is payable on the 2022 Notes on each May 15 and November 15. We may redeem some or all of the 2022 Notes at any time on or after November 15, 2017 at the redemption prices specified in the indenture, and we may redeem some or all of the 2022 Notes prior to November 15, 2017 at a make-whole redemption price as specified in the indenture. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness, or we experience certain changes of control, each as described in the indenture, we must offer to repurchase the 2022 Notes. The 2022 Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. The violation of any of these covenants could give rise to a default, which if not cured could give the holder of the 2022 Notes a right to accelerate payment. At December 31, 2015, $7,266 had been accrued in connection with the May 15, 2016 interest payment.

Deferred Financing Cost and Interest Cost

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, "Interest - Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs" which requires the presentation of debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability and not as a separate asset. In August 2015, the guidance was further clarified to state that debt issuance costs related to line-of-credit arrangements could be reported as a deferred asset and subsequently amortized ratably over the term of the line-of-credit agreement. We have elected to early adopt this standard effective December 31, 2015.

As a result of our early adoption of ASU 2015-03, deferred financing costs, net of accumulated amortization, related to the 2017 Convertible Notes, 2022 Notes and Building Loan were reclassified from other assets to a direct deduction from the carrying amount of the debt liabilities. At December 31, 2015 and 2014, approximately $6,869 and $8,754, respectively, of unamortized deferred financing costs were deducted from the carrying amount of the related debt liabilities for the 2017 Convertible Notes, 2022 Notes and Building Loan. The deferred financing costs, net of accumulated amortization, of $2,845 and $3,661 at December 31, 2015 and 2014, respectively, related to the bank credit facility remain classified as other assets.

The costs associated with the 2017 Convertible Notes are being amortized over the life of the notes using a method that applies an effective interest rate of 7.51%. The costs associated with the November 2012 issuance and November 2013 issuance of the 2022 Notes are being amortized over the life of the notes using a method that applies effective interest rates of 7.75% and 7.04%, respectively. The costs associated with the Building Loan are being amortized using the effective interest method over the term of the Building Loan. The costs associated with the bank credit facility are being amortized on a straight-line basis over the term of the facility.

Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2015, 2014 and 2013 was $85,267, $84,577 and $79,697 respectively.

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NOTE 12 — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):

Changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2015, 2014 and 2013 were as follows:



	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2015
Beginning balance, net of tax	$	86,783		$	(3,468	)	$	83,315
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	52,630			—			52,630
Foreign currency translations	—			(2,605		)	(2,605		)
Income tax effect	(19,096		)	—			(19,096		)
Net of tax	33,534			(2,605		)	30,929
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	149,955			—			149,955
Derivative income, net	1,170			—			1,170
Income tax effect	(54,833		)	—			(54,833		)
Net of tax	96,292			—			96,292
Other comprehensive loss, net of tax	(62,758		)	(2,605		)	(65,363		)
Ending balance, net of tax	$	24,025		$	(6,073	)	$	17,952



	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2014
Beginning balance, net of tax	$	(1,395	)	$	(667	)	$	(2,062	)
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	136,097			—			136,097
Foreign currency translations	—			(2,801		)	(2,801		)
Income tax effect	(48,995		)	—			(48,995		)
Net of tax	87,102			(2,801		)	84,301
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	526			—			526
Derivative expense, net	(2,208		)	—			(2,208		)
Income tax effect	606			—			606
Net of tax	(1,076		)	—			(1,076		)
Other comprehensive income (loss), net of tax	88,178			(2,801		)	85,377
Ending balance, net of tax	$	86,783		$	(3,468	)	$	83,315

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	Cash Flow Hedges			Foreign Currency Items			Total
For the Year Ended December 31, 2013
Beginning balance, net of tax	$	28,833		$	—		$	28,833
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	(26,945		)	—			(26,945		)
Foreign currency translations	—			(667		)	(667		)
Income tax effect	9,701			—			9,701
Net of tax	(17,244		)	(667		)	(17,911		)
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/natural gas production	20,289			—			20,289
Income tax effect	(7,305		)	—			(7,305		)
Net of tax	12,984			—			12,984
Other comprehensive loss, net of tax	(30,228		)	(667		)	(30,895		)
Ending balance, net of tax	$	(1,395	)	$	(667	)	$	(2,062	)

NOTE 13 — SHARE-BASED COMPENSATION:

We currently maintain the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, as amended from time to time (the “2009 Plan”). The 2009 Plan was originally approved at the 2009 Annual Meeting of Stockholders and is an amendment and restatement of the company’s 2004 Amended and Restated Stock Incentive Plan (the “2004 Plan”), and it supersedes and replaces in its entirety the 2004 Plan. The 2009 Plan provides for the granting of (a) “incentive” stock options as defined in Section 422 of the Code, (b) stock options that do not constitute incentive stock options (“non-statutory” stock options), (c) stock appreciation rights in conjunction with an incentive or non-statutory stock option, (d) restricted stock, (e) restricted stock units, (f) dividend equivalents, (g) other stock-based awards, (h) conversion awards, and (i) cash awards, any of which may be further designated as performance awards (collectively referred to as “awards”). See Note 16 - Employee Benefit Plans-Stock Incentive Plans for more information.

No stock options have been granted pursuant to the 2009 Plan since its initial effective date on May 28, 2009; however, we have previously granted options under the 2004 Plan that remain outstanding. Stock options previously granted to employees vested ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock options issued to non-employee directors vested ratably over a three-year service-vesting period and expire 10 years subsequent to award. We have granted restricted stock awards under the 2009 Plan, which awards typically vest over a one-year or three-year period.

We record share-based compensation expense under U.S. GAAP for share-based compensation awards based on the fair value on the date of grant. Compensation expense for share-based compensation awards is recognized in our financial statements over the vesting period of the award.

For the year ended December 31, 2015, we incurred $17,917 of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5,593 was capitalized into oil and gas properties. For the year ended December 31, 2014, we incurred $17,051 of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5,797 was capitalized into oil and gas properties. For the year ended December 31, 2013, we incurred $15,425 of share-based compensation, of which $15,405 related to restricted stock issuances and $20 related to stock option grants, and of which a total of approximately $5,078 was capitalized into oil and gas properties. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash provided by operating activities in our statement of cash flows. The capitalized portion is not included in net cash used in investing activities.

Stock Options. There were no stock option grants during the years ended December 31, 2015, 2014 or 2013.

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A summary of stock option activity during the year ended December 31, 2015 is as follows (amounts in table represent actual values except where indicated otherwise):



	Number of Options		Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	204,974		$	33.94
Granted	—		—
Exercised	—		—
Forfeited	—		—
Expired	(60,500	)	50.68
Options outstanding, end of period	144,474		26.92		2.1 years	$	—
Options exercisable, end of period	144,474		26.92		2.1 years	—
Options unvested, end of period	—		—		—	—

Exercise prices for stock options outstanding at December 31, 2015 range from $6.97 to $47.75.

A summary of stock option activity during the year ended December 31, 2014 is as follows (amounts in table represent actual values except where indicated otherwise):



	Number of Options		Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	331,174		$	39.37
Granted	—		—
Exercised	(250	)	46.20
Forfeited	—		—
Expired	(125,950	)	48.21
Options outstanding, end of period	204,974		33.94		2.4 years	$	531
Options exercisable, end of period	204,974		33.94		2.4 years	531
Options unvested, end of period	—		—		—	—

A summary of stock option activity during the year ended December 31, 2013 is as follows (amounts in table represent actual values except where indicated otherwise):



	Number of Options		Wgtd. Avg. Exercise Price		Wgtd. Avg. Term	Aggregate Intrinsic Value (in thousands)
Options outstanding, beginning of period	411,794		$	39.04
Granted	—		—
Exercised	—		—
Forfeited	(15,250	)	42.45
Expired	(65,370	)	36.56
Options outstanding, end of period	331,174		39.37		2.2 years	$	1,708
Options exercisable, end of period	318,279		40.62		2.1 years	1,373
Options unvested, end of period	12,895		8.64		5.0 years	335

Restricted Stock. The fair value of restricted shares is typically determined based on the average of our high and low stock prices on the grant date. During the year ended December 31, 2015, we issued 1,420,475 shares of restricted stock valued at $23,722. During the year ended December 31, 2014, we issued 674,904 shares of restricted stock valued at $24,593. During the year ended December 31, 2013, we issued 848,498 shares of restricted stock valued at $17,487.

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A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2015, 2014 and 2013 is as follows (amounts in table represent actual values):



	2015				2014				2013
	Number of Restricted Shares		Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares		Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares		Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding, beginning of period	1,303,106		$	29.95	1,258,053		$	23.92	1,108,874		$	27.56
Issuances	1,420,475		16.70		674,904		36.44		848,498		20.61
Lapse of restrictions	(638,582	)	29.60		(598,796	)	24.57		(534,041	)	25.45
Forfeitures	(278,442	)	22.39		(31,055	)	30.19		(165,278	)	26.43
Restricted stock outstanding, end of period	1,806,557		$	20.83	1,303,106		$	29.95	1,258,053		$	23.92

As of December 31, 2015, there was $20,423 of unrecognized compensation cost related to all non-vested share-based compensation arrangements under the 2009 Plan. That cost is being amortized on a straight-line basis over the vesting period and is expected to be recognized over a weighted-average period of 1.7 years.

Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital and/or an increase in income tax expense, depending on the pool of available excess tax benefits to offset such deficit. Adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting were $0, ($54) and ($884) in 2015, 2014 and 2013, respectively. Additionally, during 2015 and 2014, $1,314 and $609 of tax deficits were charged to income tax expense, respectively.

NOTE 14 — SHARE REPURCHASE PROGRAM:

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100,000. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. These withheld shares are not issued or considered common stock repurchases under our authorized share repurchase program. Through December 31, 2015, 300,000 shares had been repurchased under this program at a total cost of $7,071, or an average price of $23.57 per share. No shares were repurchased during the years ended December 31, 2015, 2014 and 2013.

NOTE 15 — COMMITMENTS AND CONTINGENCIES:

Leases

We lease office facilities in Lafayette and New Orleans, Louisiana, Houston, Texas and New Martinsville and Morgantown, West Virginia under the terms of long-term, non-cancelable leases expiring on various dates through 2021. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net annual commitments under all leases, subleases and contracts with non-cancelable terms in excess of 12 months at December 31, 2015 were as follows:



2016	$	2,022
2017	809
2018	612
2019	453
2020	453
2021	113

Payments related to our lease obligations for the years ended December 31, 2015, 2014 and 2013 were approximately $2,076, $966 and $597, respectively.

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Other Commitments and Contingencies

We are contingently liable to surety insurance companies in the amount of $223,441 relative to bonds issued on our behalf to the Bureau of Ocean Energy Management (the “BOEM”), federal and state agencies and certain third parties from which we purchased oil and gas working interests. The bonds represent guarantees by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements.

In connection with our exploration and development efforts, we are contractually committed to the use of drilling rigs and the acquisition of seismic data in the aggregate amount of $185,680 to be incurred over the next 3 years.

The Oil Pollution Act (the “OPA”) imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA and a final rule adopted by the BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10,000 in specified state waters to at least $35,000 in Outer Continental Shelf ("OCS") waters, with higher amounts of up to $150,000 in certain limited circumstances where the BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the BOEM’s final rule. In addition, the BOEM has finalized rules that raise OPA's damages liability cap from $75,000 to $133,650.

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 Notice to Lessees (" 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.

Litigation

On August 2, 2013, Kimmeridge Energy Exploration Fund, L.P. (“Kimmeridge”) filed a lawsuit against Stone in the 15th Judicial District Court in Lafayette Parish, Louisiana seeking damages in the amount of $18,373 plus interest, costs and attorney fees. Kimmeridge alleged that Stone was obligated to pay Kimmeridge (1) $1,119 for brokerage costs incurred pursuant to a letter of understanding and (2) $17,254 pursuant to a letter of intent which, according to Kimeridge's pleadings, required Stone to negotiate in good faith and close an acquisition of mineral interests in the Illinois basin. The court granted summary judgment in favor of Stone, limiting damages on Kimmeridge’s $17,254 claim to $1,000 and reducing Stone's exposure at trial for both claims to $2,119. During the three months ended June 30, 2015, Stone and Kimmeridge settled both claims for an amount within the previously disclosed range of loss (between $0 and $2,119).

NOTE 16 — EMPLOYEE BENEFIT PLANS:

We have entered into deferred compensation and disability agreements with certain of our current and former officers. The benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2015, the liability for such vested benefits was approximately $1,125 and is recorded in current and other long-term liabilities.

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

Annual Cash Incentive Compensation Plan

The Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, provides for annual cash incentive bonuses that are tied to the achievement of certain strategic objectives as defined by our board of directors on an annual basis. Stone incurred expenses of $2,242, $10,361, and $15,340, net of amounts capitalized, for each of the years

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ended December 31, 2015, 2014 and 2013, respectively, related to incentive compensation bonuses to be paid under the revised plan.

Stock Incentive Plans

We currently maintain the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, as amended from time to time (the “2009 Plan”). The 2009 Plan was originally approved at the 2009 Annual Meeting of Stockholders and is an amendment and restatement of the company’s 2004 Amended and Restated Stock Incentive Plan (the “2004 Plan”), and it supersedes and replaces in its entirety the 2004 Plan. The 2009 Plan provides for the granting of (a) “incentive” stock options as defined in Section 422 of the Code, (b) stock options that do not constitute incentive stock options (“non-statutory” stock options), (c) stock appreciation rights in conjunction with an incentive or non-statutory stock option, (d) restricted stock, (e) restricted stock units, (f) dividend equivalents, (g) other stock-based awards, (h) conversion awards, and (i) cash awards, any of which may be further designated as performance awards (collectively referred to as “awards”). The 2009 Plan eliminated the automatic grant of stock options or restricted stock awards to nonemployee directors that was provided for in the 2004 Plan so that awards under the 2009 Plan are entirely at the discretion of our board of directors or a designated committee. All options must have an exercise price of not less than the fair market value of our common stock on the date of grant and may not be re-priced without stockholder approval.

At the 2015 Annual Meeting of Stockholders, the stockholders approved the Second Amendment (the “Second Amendment”) to the 2009 Plan and the Third Amendment (the "Third Amendment") to the 2009 Plan. The Second Amendment provides, among other things, for an increase in the number of shares of our common stock reserved for issuance under the 2009 Plan by 1,600,000 shares, effective May 21, 2015, and for an extension of the term of the 2009 Plan to May 21, 2025. The Third Amendment sets forth the material terms of the 2009 Plan (i.e., the eligible employees, business criteria and maximum annual per person compensation limits) for purposes of complying with certain requirements of Section 162(m) of the Internal Revenue Code. The Third Amendment does not change the employees eligible to receive compensation under the 2009 Plan, but does (i) allow Stone to grant cash awards (which may or may not be designated as performance awards) under the 2009 Plan, (ii) impose a fixed share number limit on stock-based awards and a fixed dollar limit on cash awards granted during any calendar year under the 2009 Plan to certain individuals, and (iii) add additional business criteria that may be utilized in setting performance goals under the 2009 Plan. The Third Amendment also became effective as of May 21, 2015. On December 17, 2015, Stone amended and restated the 2009 Plan to incorporate all prior amendments to the 2009 Plan (including the Second Amendment and the Third Amendment) and certain other non-material changes to the 2009 Plan.

At December 31, 2015, we had approximately 2,082,434 additional shares available for issuance pursuant to the 2009 Plan.

401(k) and Deferred Compensation Plans

The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 2015, 2014 and 2013, Stone contributed $1,553, $1,989 and $1,793, respectively, to the plan.

The Stone Energy Corporation Deferred Compensation Plan provides eligible executives and employees with the option to defer up to 100% of their eligible compensation for a calendar year and we may, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by our board of directors. In addition, the Board may elect to make discretionary profit sharing contributions to the plan. To date there have been no matching or discretionary profit sharing contributions made by Stone. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At December 31, 2015 and 2014, plan assets of $8,499 and $8,425, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.

Change of Control and Severance Plans

On April 7, 2009, we amended and restated our Executive Change of Control and Severance Plan effective as of December 31, 2008 (as so amended and restated, the “Executive Plan”). The Executive Plan also replaced and superseded our Executive Change in Control and Severance Policy that was maintained for certain designated executives (specifically, the CEO and CFO). The Executive Plan will provide the company’s officers that are terminated in the event of a change of control and upon certain other terminations of employment with change of control and severance benefits as defined in the Executive Plan. Although our CEO does not currently participate in the Executive Plan, the severance benefits provided to him under his employee agreement are substantially similar to the benefits provided under the Executive Plan. Executives who are terminated within the scope of the Executive Plan will be entitled to certain payments and benefits including the following: (i) any unpaid base salary up to the date of termination; (ii) in the case of the CEO and CFO, a lump sum severance payment of 2.99 times the sum of the executive’s

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annual base salary and any target bonus at the one hundred percent level; (iii) a lump sum amount representing a pro rata share of the bonus opportunity up to the date of termination at the then projected rate of payout; (iv) in the case of officers other than the CEO and CFO and an involuntary termination occurring outside a change of control period, a lump sum severance payment in an amount equal to the executive’s annual base salary; (v) in the case of officers other than the CEO and CFO and an involuntary termination occurring during a change of control period, a lump sum severance payment in an amount equal to 2.99 times the executive’s annual base salary; (vi) continued health plan coverage for six months and outplacement services. In the case of the CEO and CFO, if the payments would be “excess parachute payments,” the CEO and CFO may receive a potential gross-up payment to reimburse them for excise taxes that might be incurred under Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”), as well as any additional income taxes resulting from such reimbursement, provided that if it shall be determined that the executive is entitled to a gross-up payment but the total to be paid does not exceed 110% of the greatest amount (the “Reduced Amount”) that could be paid such that receipt of the total would not give rise to any excise tax, then no gross-up will be paid and the total payments to the executive will be reduced to the Reduced Amount. Also, if a payment would be to a “specified employee” for purposes of Section 409A of the Code, payment will be delayed until six months after his termination if required to comply with Section 409A. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: (i) lapse of restrictions on restricted stock, (ii) accelerated vesting and cash-out of all in-the-money stock options, (iii) a 401(k) plan employer matching contribution at the rate of 50%, and (iv) a pro-rated portion of the projected bonus, if any, for the year of change of control.

On December 7, 2007, our board of directors approved and adopted the Stone Energy Corporation Employee Change of Control Severance Plan (“Employee Severance Plan”), as amended and restated to comply with the final regulations under Section 409A of the Code and to provide that said plan will remain in force and effect unless and until terminated by our board of directors. The Employee Severance Plan amended and restated the company’s previous Employee Change of Control Severance Plan dated November 16, 2006. The Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the six-month period following a change of control, including a resignation by the employee relating to a change in duties. Employees who are terminated within the scope of the Employee Severance Plan will be entitled to certain payments and benefits including the following: (i) a lump sum equal to (1) weekly pay times full years of service, plus (2) one week’s pay for each full $10,000 of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay; (ii) continued health plan coverage for 6 months; (iii) a pro-rated portion of the employee’s targeted bonus for the year, and (iv) reasonable outplacement services consistent with current HR practices. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: (i) lapse of restrictions on restricted stock, (ii) cash-out of in-the-money stock options, (iii) a 401(k) plan employer matching contribution at the rate of 50%, and (iv) a lump sum cash payment equal to the product of (1) the number of “restricted shares” of company stock that the employee would have received under the company’s stock plan but did not receive for the time-vested portion of his long-term stock incentive award, if any, for the calendar year in which the change of control occurs times (2) the price per share of the company’s common stock utilized in effecting the change of control, provided that such amount shall be pro-rated by multiplying such amount by the number of full months that have elapsed from January 1 of that calendar year to the effective date of the change of control and then dividing the result by 12.

NOTE 17 — SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED:

At December 31, 2015, 2014 and 2013, our oil and gas properties were located in the United States and Canada.

Costs Incurred

The following table discloses certain financial data relative to our oil and gas producing activities located onshore and offshore in the continental United States:

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	Year Ended December 31,
	2015			2014			2013
Oil and gas properties – United States, proved and unevaluated:
Balance, beginning of year	$	9,348,054		$	8,517,873		$	7,692,261
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties	(14,158		)	44,634			70,903
Exploratory costs	104,169			270,850			297,113
Development costs (1)	266,982			438,334			378,242
Salaries, general and administrative costs	27,984			33,975			32,815
Interest	41,339			45,722			46,860
Less: overhead reimbursements	(913		)	(3,334		)	(321		)
Total costs incurred during the year, net of divestitures	425,403			830,181			825,612
Balance, end of year	$	9,773,457		$	9,348,054		$	8,517,873
Accumulated DD&A:
Balance, beginning of year	$	(6,970,631	)	$	(5,908,760	)	$	(5,510,166	)
Provision for DD&A	(277,088		)	(335,987		)	(346,827		)
Write-down of oil and gas properties	(1,314,817		)	(351,192		)	—
Sale of proved properties	1,064			(374,692		)	(51,767		)
Balance, end of year	$	(8,561,472	)	$	(6,970,631	)	$	(5,908,760	)
Net capitalized costs – United States, proved and unevaluated	$	1,211,985		$	2,377,423		$	2,609,113
DD&A per Mcfe	$	3.19		$	3.59		$	3.43
(1) Includes capitalized asset retirement costs of ($43,901), ($20,305) and $54,737, respectively.
Costs incurred during the year (expensed):
Lease operating expenses	$	100,139		$	176,495		$	201,153
Transportation, processing and gathering expenses	58,847			64,951			42,172
Production taxes	6,877			12,151			15,029
Accretion expense	25,988			28,411			33,575
Expensed costs – United States	$	191,851		$	282,008		$	291,929

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

At March 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $491,412 based on 12-month average prices, net of applicable differentials, of $78.99 per Bbl of oil, $2.96 per Mcf of natural gas and $28.82 per Bbl of natural gas liquids ("NGLs"). At June 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $179,125 based on 12-month average prices, net of applicable differentials, of $68.68 per Bbl of oil, $2.47 per Mcf of natural gas and $29.13 per Bbl of NGLs. At September 30, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $295,679 based on 12-month average prices, net of applicable differentials, of $57.76 per Bbl of oil, $2.44 per Mcf of natural gas and $23.04 per Bbl of NGLs. At December 31, 2015, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $348,601 based on 12-month average prices, net of applicable differentials, of $51.16 per Bbl of oil, $2.19 per Mcf of natural gas and $16.40 per Bbl of NGLs. The March 31, June 30, September 30 and December 31, 2015 write-downs were decreased by $28,687, $47,784, $42,652 and $24,797, respectively, as a result of hedges.

At September 30, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $47,130 based on 12-month average prices, net of applicable differentials, of $94.94 per Bbl of oil, $4.19 per Mcf of natural gas and $41.33 per Bbl of NGLs. At December 31, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $304,062 based on 12-month average prices, net of applicable differentials, of $89.46 per Bbl of oil, $3.68 per Mcf of natural

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gas and $36.79 per Bbl of NGLs. The September 30 and December 31, 2014 write-downs were increased by $29,001 and $13,342, respectively, as a result of hedges.

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



	Year Ended December 31,
Unevaluated oil and gas properties – United States:	2015			2014			2013
Net costs incurred (evaluated) during year:
Acquisition costs	$	(115,767	)	$	(42,384	)	$	30,271
Exploration costs	(16,315		)	(186,308		)	188,830
Capitalized interest	41,339			45,722			46,860
	$	(90,743	)	$	(182,970	)	$	265,961

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



	Year Ended December 31,
	2015			2014		2013
Oil and gas properties – Canada:
Balance, beginning of year	$	36,579		$	10,583	$	—
Costs incurred during the year (capitalized):
Acquisition costs	(2,862		)	6,956		8,764
Exploratory costs	8,767			19,040		1,819
Total costs incurred during the year	5,905			25,996		10,583
Balance, end of year (fully evaluated at December 31, 2015 and unevaluated at December 31, 2014 and 2013)	$	42,484		$	36,579	$	10,583
Accumulated DD&A:
Balance, beginning of year	$	—		$	—	$	—
Foreign currency translation adjustment	5,146			$	—	—
Write-down of oil and gas properties	(47,630		)	$	—	—
Balance, end of year	$	(42,484	)	$	—	$	—
Net capitalized costs – Canada	$	—		$	36,579	$	10,583

The following table discloses financial data associated with unevaluated costs (United States) at December 31, 2015:



	Balance as of		Net Costs Incurred During the Year Ended December 31,
	December 31, 2015		2015			2014			2013		2012 and prior
Acquisition costs	$	173,902	$	(33,623	)	$	(5,118	)	$	40,535	$	172,108
Exploration costs	148,518		41,936			42,899			42,186		21,497
Capitalized interest	117,623		20,257			23,538			24,162		49,666
Total unevaluated costs	$	440,043	$	28,570		$	61,319		$	106,883	$	243,271

Approximately 95 specifically identified drilling projects are included in unevaluated costs at December 31, 2015 and are expected to be evaluated in the next four years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs capitalized on unevaluated properties during the years ended December 31, 2015, 2014 and 2013 totaled $41,339, $45,722 and $46,860, respectively.

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Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2015 have been prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

The following table sets forth an analysis of the estimated quantities of net proved oil (including condensate), natural gas and NGL reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil, natural gas and NGL reserves at December 31, 2015, 2014 and 2013 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical 12-month average pricing assumption.



	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Oil, Natural Gas and NGLs (MMcfe)
Estimated proved reserves as of December 31, 2012	44,918		18,066		395,374		773,285
Revisions of previous estimates	3,606		2,439		36,006		72,275
Extensions, discoveries and other additions	2,367		4,395		79,729		120,299
Sale of reserves	(170	)	—		(214	)	(1,235	)
Production	(6,894	)	(1,603	)	(50,129	)	(101,111	)
Estimated proved reserves as of December 31, 2013	43,827		23,297		460,766		863,513
Revisions of previous estimates	(624	)	(331	)	(4,631	)	(10,362	)
Extensions, discoveries and other additions	9,650		7,521		131,617		234,639
Sale of reserves	(4,888	)	(556	)	(46,483	)	(79,151	)
Production	(5,568	)	(2,114	)	(47,426	)	(93,515	)
Estimated proved reserves as of December 31, 2014	42,397		27,817		493,843		915,124
Revisions of previous estimates	(6,818	)	(20,777	)	(362,102	)	(527,675	)
Extensions, discoveries and other additions	862		11		1,499		6,738
Purchase of producing properties	685		1,808		26,136		41,095
Sale of reserves	(859	)	—		(1,061	)	(6,213	)
Production	(5,991	)	(2,401	)	(36,457	)	(86,809	)
Estimated proved reserves as of December 31, 2015	30,276		6,458		121,858		342,260
Estimated proved developed reserves:
as of December 31, 2013	27,920		11,569		246,946		483,885
as of December 31, 2014	22,957		13,743		249,924		470,118
as of December 31, 2015	21,734		4,784		90,262		249,366
Estimated proved undeveloped reserves:
as of December 31, 2013	15,907		11,728		213,820		379,628
as of December 31, 2014	19,440		14,074		243,919		445,006
as of December 31, 2015	8,542		1,674		31,596		92,894

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

Year Ended December 31, 2015. Revisions of previous estimates were primarily the result of the significant decline in commodity prices resulting in uneconomic reserves (570 Bcfe) primarily in Appalachia, slightly offset by positive well performance (42 Bcfe). Purchase of producing properties related to increases in our net revenue and working interests in multiple wells in the Mary field in Appalachia resulting from the finalization of participation elections made by partners and potential partners in certain units.

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Year Ended December 31, 2014. Extensions, discoveries and other additions were primarily the result of our Appalachia (118 Bcfe) and our deep water (116 Bcfe) drilling programs. Sale of reserves primarily related to the sale of certain of our non-core GOM conventional shelf properties (63 Bcfe) and our Katie field in Appalachia (15 Bcfe).

Year Ended December 31, 2013. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (117 Bcfe). Revisions of previous estimates were primarily the result of positive reserve report pricing changes extending the economic limits of reservoirs (18 Bcfe) and well performance (55 Bcfe).

Standardized Measure of Discounted Future Net Cash Flow

The following tables present the standardized measure of discounted future net cash flows related to estimated proved oil, natural gas and NGL reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2015. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil, natural gas and NGL reserves. Prices are based on either the historical 12-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The 2015 average historical 12-month oil and natural gas prices, net of applicable differentials, were $51.16 per Bbl of oil, $16.40 per Bbl of NGLs and $2.19 per Mcf of natural gas. The 2014 average 12-month oil and natural gas prices, net of applicable differentials, were $89.46 per Bbl of oil, $36.79 per Bbl of NGLs and $3.68 per Mcf of natural gas. The 2013 average 12-month oil and natural gas prices, net of applicable differentials, were $102.21 per Bbl of oil, $37.59 per Bbl of NGLs and $3.66 per Mcf of natural gas. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.



	Standardized Measure Year Ended December 31,
	2015			2014			2013
Future cash inflows	$	1,921,329		$	6,635,751		$	7,040,928
Future production costs	(651,396		)	(2,413,004		)	(2,062,657		)
Future development costs	(679,355		)	(1,511,687		)	(1,431,101		)
Future income taxes	—			(609,516		)	(884,637		)
Future net cash flows	590,578			2,101,544			2,662,533
10% annual discount	13,259			(682,752		)	(977,531		)
Standardized measure of discounted future net cash flows	$	603,837		$	1,418,792		$	1,685,002



	Changes in Standardized Measure Year Ended December 31,
	2015			2014			2013
Standardized measure at beginning of year	$	1,418,792		$	1,685,002		$	1,513,859
Sales and transfers of oil, natural gas and NGLs produced, net of production costs	(340,477		)	(486,232		)	(708,017		)
Changes in price, net of future production costs	(237,747		)	(864,118		)	229,425
Extensions and discoveries, net of future production and development costs	1,573			549,649			155,592
Changes in estimated future development costs, net of development costs incurred during the period	731,115			203,026			28,684
Revisions of quantity estimates	(1,458,652		)	(27,495		)	281,558
Accretion of discount	174,456			222,009			202,087
Net change in income taxes	325,768			209,323			(28,084		)
Purchases of reserves in-place	3,493			—			—
Sales of reserves in-place	—			(152,787		)	15,531
Changes in production rates due to timing and other	(14,484		)	80,415			(5,633		)
Net increase (decrease) in standardized measure	(814,955		)	(266,210		)	171,143
Standardized measure at end of year	$	603,837		$	1,418,792		$	1,685,002

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NOTE 18 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED:

The results of operations by quarter are as follows:



	2015
	Quarter Ended
	March 31			June 30			September 30			December 31
Operating revenue	$	153,498		$	149,525		$	132,196		$	110,499
Loss from operations	(497,194		)	(228,161		)	(297,209		)	(342,759		)
Net loss	(327,388		)	(152,906		)	(291,965		)	(318,656		)
Basic loss per share	$	(5.93	)	$	(2.77	)	$	(5.28	)	$	(5.76	)
Diluted loss per share	$	(5.93	)	$	(2.77	)	$	(5.28	)	$	(5.76	)

Write-down of oil and gas properties before income tax effect	$	491,412		$	224,294		$	295,679		$	351,062
Write-down of oil and gas properties net of income tax effect	314,504			143,548			189,235			224,680



	2014
	Quarter Ended
	March 31		June 30		September 30			December 31
Operating revenue	$	223,830	$	207,046	$	183,213		$	184,780
Income (loss) from operations	48,552		16,613		(34,356		)	(286,147		)
Net income (loss)	25,943		4,444		(29,415		)	(190,515		)
Basic earnings (loss) per share	$	0.52	$	0.08	$	(0.54	)	$	(3.47	)
Diluted earnings (loss) per share	$	0.52	$	0.08	$	(0.54	)	$	(3.47	)

Write-down of oil and gas properties before income tax effect	$	—	$	—	$	47,130		$	304,062
Write-down of oil and gas properties net of income tax effect	—		—		30,163			194,600

NOTE 19 – RECENTLY ISSUED ACCOUNTING STANDARDS:

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The standard may be applied retrospectively or using a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. In August 2015, the FASB issued ASU 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for interim and annual periods beginning on or after December 31, 2017. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

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NOTE 20 – GUARANTOR FINANCIAL STATEMENTS:

Our Guarantor Subsidiaries, including Stone Offshore, SEO A LLC and SEO B LLC, are unconditional guarantors of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents consolidating financial information as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 on an issuer (parent company), Guarantor Subsidiaries, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

CCONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2015

(In thousands)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,681		$	2		$	1,076		$	—		$	10,759
Accounts receivable	10,597			39,190			—			(1,756		)	48,031
Fair value of derivative contracts	—			38,576			—			—			38,576
Current income tax receivable	46,174			—			—			—			46,174
Inventory	535			—			—			—			535
Other current assets	6,313			—			33			—			6,346
Total current assets	73,300			77,768			1,109			(1,756		)	150,421
Oil and gas properties, full cost method:
Proved	1,875,152			7,458,262			42,484			—			9,375,898
Less: accumulated DD&A	(1,874,622		)	(6,686,849		)	(42,484		)	—			(8,603,955		)
Net proved oil and gas properties	530			771,413			—			—			771,943
Unevaluated	253,308			186,735			—			—			440,043
Other property and equipment, net	29,289			—			—			—			29,289
Other assets, net	16,612			826			1,035			—			18,473
Investment in subsidiary	745,033			—			1,088			(746,121		)	—
Total assets	$	1,118,072		$	1,036,742		$	3,232		$	(747,877	)	$	1,410,169
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	16,063		$	67,901		$	—		$	(1,757	)	$	82,207
Undistributed oil and gas proceeds	5,216			776			—			—			5,992
Accrued interest	9,022			—			—			—			9,022
Asset retirement obligations	—			20,400			891			—			21,291
Other current liabilities	40,161			551			—			—			40,712
Total current liabilities	70,462			89,628			891			(1,757		)	159,224
Long-term debt	1,060,955			—			—			—			1,060,955
Asset retirement obligations	1,240			203,335			—			—			204,575
Other long-term liabilities	25,204			—			—			—			25,204
Total liabilities	1,157,861			292,963			891			(1,757		)	1,449,958
Commitments and contingencies
Stockholders’ equity:
Common stock	553			—			—			—			553
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,648,189			1,344,577			109,795			(1,454,372		)	1,648,189
Accumulated deficit	(1,705,623		)	(624,824		)	(95,306		)	720,130			(1,705,623		)
Accumulated other comprehensive income (loss)	17,952			24,026			(12,148		)	(11,878		)	17,952
Total stockholders’ equity	(39,789		)	743,779			2,341			(746,120		)	(39,789		)
Total liabilities and stockholders’ equity	$	1,118,072		$	1,036,742		$	3,232		$	(747,877	)	$	1,410,169

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CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2014

(In thousands)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	72,886		$	1,450		$	152		$	—		$	74,488
Restricted cash	177,647			—			—			—			177,647
Accounts receivable	73,711			46,615			33			—			120,359
Fair value of derivative contracts	—			139,179			—			—			139,179
Current income tax receivable	7,212			—			—			—			7,212
Deferred taxes *	4,095			—			—			(4,095		)	—
Inventory	1,011			2,698			—			—			3,709
Other current assets	8,112			—			6			—			8,118
Total current assets	344,674			189,942			191			(4,095		)	530,712
Oil and gas properties, full cost method:
Proved	1,689,802			7,127,466			—			—			8,817,268
Less: accumulated DD&A	(970,387		)	(6,000,244		)	—			—			(6,970,631		)
Net proved oil and gas properties	719,415			1,127,222			—			—			1,846,637
Unevaluated	289,556			241,230			36,579			—			567,365
Other property and equipment, net	32,340			—			—			—			32,340
Fair value of derivative contracts	—			14,333			—			—			14,333
Other assets, net	12,103			1,360			5,007			—			18,470
Investment in subsidiary	1,050,546			—			41,638			(1,092,184		)	—
Total assets	$	2,448,634		$	1,574,087		$	83,415		$	(1,096,279	)	$	3,009,857
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	74,756		$	57,873		$	—		$	—		$	132,629
Undistributed oil and gas proceeds	22,158			1,074			—			—			23,232
Accrued interest	9,022			—			—			—			9,022
Deferred taxes *	—			24,214			—			(4,095		)	20,119
Asset retirement obligations	—			69,400			—			—			69,400
Other current liabilities	49,306			199			—			—			49,505
Total current liabilities	155,242			152,760			—			(4,095		)	303,907
Long-term debt	1,032,281			—			—			—			1,032,281
Deferred taxes *	117,206			169,137			—			—			286,343
Asset retirement obligations	3,588			243,421			—			—			247,009
Other long-term liabilities	38,714			—			—			—			38,714
Total liabilities	1,347,031			565,318			—			(4,095		)	1,908,254
Commitments and contingencies
Stockholders’ equity:
Common stock	549			—			—			—			549
Treasury stock	(860		)	—			—			—			(860		)
Additional paid-in capital	1,633,307			1,362,684			90,339			(1,453,023		)	1,633,307
Accumulated earnings (deficit)	(614,708		)	(440,699		)	12			440,687			(614,708		)
Accumulated other comprehensive income (loss)	83,315			86,784			(6,936		)	(79,848		)	83,315
Total stockholders’ equity	1,101,603			1,008,769			83,415			(1,092,184		)	1,101,603
Total liabilities and stockholders’ equity	$	2,448,634		$	1,574,087		$	83,415		$	(1,096,279	)	$	3,009,857

* Deferred income taxes have been allocated to our Guarantor Subsidiaries where related oil and gas properties reside.

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2015

(In thousands)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	12,804		$	403,693		$	—		$	—		$	416,497
Natural gas production	41,646			41,863			—			—			83,509
Natural gas liquids production	22,375			9,947			—			—			32,322
Other operational income	4,369			—			—			—			4,369
Derivative income, net	—			7,952			—			—			7,952
Total operating revenue	81,194			463,455			—			—			544,649
Operating expenses:
Lease operating expenses	16,264			83,872			3			—			100,139
Transportation, processing, and gathering expenses	50,247			8,600			—			—			58,847
Production taxes	5,631			1,246			—			—			6,877
Depreciation, depletion, amortization	123,724			157,964			—			—			281,688
Write-down of oil and gas properties	785,463			529,354			47,630			—			1,362,447
Accretion expense	365			25,623			—			—			25,988
Salaries, general and administrative expenses	69,147			201			36			—			69,384
Incentive compensation expense	2,242			—			—			—			2,242
Other operational expenses	2,360			—			—			—			2,360
Total operating expenses	1,055,443			806,860			47,669			—			1,909,972
Loss from operations	(974,249		)	(343,405		)	(47,669		)	—			(1,365,323		)
Other (income) expenses:
Interest expense	43,907			21			—			—			43,928
Interest income	(327		)	(246		)	(7		)	—			(580		)
Other income	(617		)	(1,163		)	(3		)	—			(1,783		)
Other expense	434			—			—			—			434
Loss from investment in subsidiaries	231,783			—			47,659			(279,442		)	—
Total other (income) expenses	275,180			(1,388		)	47,649			(279,442		)	41,999
Loss before taxes	(1,249,429		)	(342,017		)	(95,318		)	279,442			(1,407,322		)
Provision (benefit) for income taxes:
Current	(44,096		)	—			—			—			(44,096		)
Deferred	(114,418		)	(157,893		)	—			—			(272,311		)
Total income taxes	(158,514		)	(157,893		)	—			—			(316,407		)
Net loss	$	(1,090,915	)	$	(184,124	)	$	(95,318	)	$	279,442		$	(1,090,915	)
Comprehensive loss	$	(1,156,278	)	$	(184,124	)	$	(95,318	)	$	279,442		$	(1,156,278	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014

(In thousands)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	29,701		$	486,403		$	—		$	—		$	516,104
Natural gas production	86,812			79,682			—			—			166,494
Natural gas liquids production	61,200			24,442			—			—			85,642
Other operational income	7,551			400			—			—			7,951
Derivative income, net	—			19,351			—			—			19,351
Total operating revenue	185,264			610,278			—			—			795,542
Operating expenses:
Lease operating expenses	18,719			157,776			—			—			176,495
Transportation, processing, and gathering expenses	53,028			11,923			—			—			64,951
Production taxes	8,324			3,827			—			—			12,151
Depreciation, depletion, amortization	138,313			201,693			—			—			340,006
Write-down of oil and gas properties	351,192			—			—			—			351,192
Accretion expense	230			28,181			—			—			28,411
Salaries, general and administrative expenses	66,430			4			17			—			66,451
Incentive compensation expense	10,361			—			—			—			10,361
Other operational expenses	669			193			—			—			862
Total operating expenses	647,266			403,597			17			—			1,050,880
Income (loss) from operations	(462,002		)	206,681			(17		)	—			(255,338		)
Other (income) expenses:
Interest expense	38,810			45			—			—			38,855
Interest income	(333		)	(192		)	(49		)	—			(574		)
Other income	(836		)	(1,496		)	—			—			(2,332		)
Other expense	274			—			—			—			274
Income from investment in subsidiaries	(133,336		)	—			(32		)	133,368			—
Total other (income) expenses	(95,421		)	(1,643		)	(81		)	133,368			36,223
Income (loss) before taxes	(366,581		)	208,324			64			(133,368		)	(291,561		)
Provision (benefit) for income taxes:
Current	159			—			—			—			159
Deferred	(177,197		)	75,020			—			—			(102,177		)
Total income taxes	(177,038		)	75,020			—			—			(102,018		)
Net income (loss)	$	(189,543	)	$	133,304		$	64		$	(133,368	)	$	(189,543	)
Comprehensive income (loss)	$	(104,166	)	$	133,304		$	64		$	(133,368	)	$	(104,166	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2013

(In thousands)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	30,475		$	684,629		$	—		$	—		$	715,104
Natural gas production	68,895			121,685			—			—			190,580
Natural gas liquids production	32,293			28,394			—			—			60,687
Other operational income	7,163			645			—			—			7,808
Total operating revenue	138,826			835,353			—			—			974,179
Operating expenses:
Lease operating expenses	14,680			186,473			—			—			201,153
Transportation, processing and gathering expenses	28,322			13,850			—			—			42,172
Production taxes	6,229			8,800			—			—			15,029
Depreciation, depletion, amortization	93,579			256,995			—			—			350,574
Accretion expense	372			33,203			—			—			33,575
Salaries, general and administrative expenses	59,473			5			46			—			59,524
Franchise tax settlement	12,590			—			—			—			12,590
Incentive compensation expense	15,340			—			—			—			15,340
Other operational expenses	38			113			—			—			151
Derivative expense, net	—			2,090			—			—			2,090
Total operating expenses	230,623			501,529			46			—			732,198
Income (loss) from operations	(91,797		)	333,824			(46		)	—			241,981
Other (income) expenses:
Interest expense	32,816			21			—			—			32,837
Interest income	(1,480		)	(195		)	(20		)	—			(1,695		)
Other income	(875		)	(1,924		)	—			—			(2,799		)
Loss on early extinguishment of debt	27,279			—			—			—			27,279
(Income) loss from investment in subsidiaries	(214,983		)	—			26			214,957			—
Total other (income) expenses	(157,243		)	(2,098		)	6			214,957			55,622
Income (loss) before taxes	65,446			335,922			(52		)	(214,957		)	186,359
Provision (benefit) for income taxes:
Current	(10,904		)	—			—			—			(10,904		)
Deferred	(41,284		)	120,913			—			—			79,629
Total income taxes	(52,188		)	120,913			—			—			68,725
Net income (loss)	$	117,634		$	215,009		$	(52	)	$	(214,957	)	$	117,634
Comprehensive income (loss)	$	86,739		$	215,009		$	(52	)	$	(214,957	)	$	86,739

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2015

(In thousands)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net loss	$	(1,090,915	)	$	(184,124	)	$	(95,318	)	$	279,442		$	(1,090,915	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	123,724			157,964			—			—			281,688
Write-down of oil and gas properties	785,463			529,354			47,630			—			1,362,447
Accretion expense	365			25,623			—			—			25,988
Deferred income tax benefit	(114,418		)	(157,893		)	—			—			(272,311		)
Settlement of asset retirement obligations	(15		)	(72,367		)	—			—			(72,382		)
Non-cash stock compensation expense	12,324			—			—			—			12,324
Excess tax benefits	(1,586		)	—			—			—			(1,586		)
Non-cash derivative expense	—			16,440			—			—			16,440
Non-cash interest expense	17,788			—			—			—			17,788
Change in current income taxes	(37,377		)	—			—			—			(37,377		)
Non-cash loss from investment in subsidiaries	231,783			—			47,659			(279,442		)	—
Change in intercompany receivables/payables	9,744			(19,486		)	9,742			—			—
Decrease in accounts receivable	34,609			9,084			31			—			43,724
(Increase) decrease in other current assets	1,799			—			(32		)	—			1,767
(Increase) decrease in inventory	(1,394		)	2,698			—			—			1,304
Decrease in accounts payable	(7,471		)	(7,111		)	—			—			(14,582		)
Increase (decrease) in other current liabilities	(25,989		)	53			—			—			(25,936		)
Other	256			(1,163		)	—			—			(907		)
Net cash (used in) provided by operating activities	(61,310		)	299,072			9,712			—			247,474
Cash flows from investing activities:
Investment in oil and gas properties	(188,154		)	(323,359		)	(10,534		)	—			(522,047		)
Proceeds from sale of oil and gas properties, net of expenses	—			22,839			—			—			22,839
Investment in fixed and other assets	(1,549		)	—			—			—			(1,549		)
Change in restricted funds	177,647			—			1,820			—			179,467
Investment in subsidiaries	—			—			(9,714		)	9,714			—
Net cash used in investing activities	(12,056		)	(300,520		)	(18,428		)	9,714			(321,290		)
Cash flows from financing activities:
Proceeds from bank borrowings	5,000			—			—			—			5,000
Repayments of bank borrowings	(5,000		)	—			—			—			(5,000		)
Deferred financing costs	(68		)	—			—			—			(68		)
Proceeds from building loan	11,770			—			—			—			11,770
Equity proceeds from parent	—			—			9,714			(9,714		)	—
Excess tax benefits	1,586			—			—			—			1,586
Net payments for share-based compensation	(3,127		)	—			—			—			(3,127		)
Net cash provided by financing activities	10,161			—			9,714			(9,714		)	10,161
Effect of exchange rate changes on cash	—			—			(74		)	—			(74		)
Net change in cash and cash equivalents	(63,205		)	(1,448		)	924			—			(63,729		)
Cash and cash equivalents, beginning of period	72,886			1,450			152			—			74,488
Cash and cash equivalents, end of period	$	9,681		$	2		$	1,076		$	—		$	10,759

F-39

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014

(In thousands)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(189,543	)	$	133,304		$	64		$	(133,368	)	$	(189,543	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	138,313			201,693			—			—			340,006
Write-down of oil and gas properties	351,192			—			—			—			351,192
Accretion expense	230			28,181			—			—			28,411
Deferred income tax (benefit) provision	(177,197		)	75,020			—			—			(102,177		)
Settlement of asset retirement obligations	(201		)	(56,208		)	—			—			(56,409		)
Non-cash stock compensation expense	11,325			—			—			—			11,325
Non-cash derivative income	—			(18,028		)	—			—			(18,028		)
Non-cash interest expense	16,661			—			—			—			16,661
Change in current income taxes	158			—			—			—			158
Non-cash income from investment in subsidiaries	(133,336		)	—			(32		)	133,368			—
Change in intercompany receivables/payables	114,056			(145,250		)	31,194			—			—
(Increase) decrease in accounts receivable	1,131			50,514			(34		)	—			51,611
Increase in other current assets	(6,238		)	—			(6		)	—			(6,244		)
(Increase) decrease in inventory	2,415			(2,415		)	—			—			—
Decrease in accounts payable	(662		)	(2,757		)	—			—			(3,419		)
Decrease in other current liabilities	(16,946		)	(2,206		)	—			—			(19,152		)
Other	(1,755		)	(1,496		)	—			—			(3,251		)
Net cash provided by operating activities	109,603			260,352			31,186			—			401,141
Cash flows from investing activities:
Investment in oil and gas properties	(338,731		)	(558,003		)	(30,513		)	—			(927,247		)
Proceeds from sale of oil and gas properties, net of expenses	28,103			214,811			—			—			242,914
Investment in fixed and other assets	(10,182		)	—			—			—			(10,182		)
Change in restricted funds	(177,647		)	—			(425		)	—			(178,072		)
Investment in subsidiaries	—			—			(31,696		)	31,696			—
Net cash used in investing activities	(498,457		)	(343,192		)	(62,634		)	31,696			(872,587		)
Cash flows from financing activities:
Proceeds from issuance of common stock	225,999			—			—			—			225,999
Deferred financing costs	(3,371		)	—			—			—			(3,371		)
Equity proceeds from parent	—			—			31,696			(31,696		)	—
Net payments for share-based compensation	(7,182		)	—			—			—			(7,182		)
Net cash provided by financing activities	215,446			—			31,696			(31,696		)	215,446
Effect of exchange rate changes on cash	—			—			(736		)	—			(736		)
Net change in cash and cash equivalents	(173,408		)	(82,840		)	(488		)	—			(256,736		)
Cash and cash equivalents, beginning of period	246,294			84,290			640			—			331,224
Cash and cash equivalents, end of period	$	72,886		$	1,450		$	152		$	—		$	74,488

F-40

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2013

(In thousands)



	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	117,634		$	215,009		$	(52	)	$	(214,957	)	$	117,634
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	93,579			256,995			—			—			350,574
Accretion expense	372			33,203			—			—			33,575
Deferred income tax provision (benefit)	(41,284		)	120,913			—			—			79,629
Settlement of asset retirement obligations	—			(83,854		)	—			—			(83,854		)
Non-cash stock compensation expense	10,347			—			—			—			10,347
Excess tax benefits	(156		)	—			—			—			(156		)
Non-cash derivative expense	—			2,239			—			—			2,239
Loss on early extinguishment of debt	27,279			—			—			—			27,279
Non-cash interest expense	16,219			—			—			—			16,219
Change in current income taxes	2,767			—			—			—			2,767
Non-cash (income) loss from investment in subsidiaries	(214,983		)	—			26			214,957			—
Change in intercompany receivables/payables	186,903			(186,947		)	44			—			—
(Increase) decrease in accounts receivable	(15,630		)	10,947			—			—			(4,683		)
Decrease in other current assets	1,752			—			—			—			1,752
Decrease in inventory	583			—			—			—			583
Increase (decrease) in accounts payable	(1,052		)	1,454			—			—			402
Increase in other current liabilities	40,543			1,908			—			—			42,451
Other	419			(2,972		)	—			—			(2,553		)
Net cash provided by operating activities	225,292			368,895			18			—			594,205
Cash flows from investing activities:
Investment in oil and gas properties	(273,474		)	(378,254		)	(11,571		)	—			(663,299		)
Proceeds from sale of oil and gas properties, net of expenses	6,300			42,521			—			—			48,821
Investment in fixed and other assets	(6,816		)	—			—			—			(6,816		)
Change in restricted funds	—			—			(1,742		)	—			(1,742		)
Investment in subsidiaries	(14,000		)	—			(13,404		)	27,404			—
Net cash used in investing activities	(287,990		)	(335,733		)	(26,717		)	27,404			(623,036		)
Cash flows from financing activities:
Proceeds from issuance of senior notes	489,250			—			—			—			489,250
Deferred financing costs	(9,065		)	—			—			—			(9,065		)
Redemption of senior notes	(396,014		)	—			—			—			(396,014		)
Excess tax benefits	156			—			—			—			156
Equity proceeds from parent	—			—			27,404			(27,404		)	—
Net payments for share-based compensation	(3,733		)	—			—			—			(3,733		)
Net cash provided by financing activities	80,594			—			27,404			(27,404		)	80,594
Effect of exchange rate changes on cash	—			—			(65		)	—			(65		)
Net change in cash and cash equivalents	17,896			33,162			640			—			51,698
Cash and cash equivalents, beginning of period	228,398			51,128			—			—			279,526
Cash and cash equivalents, end of period	$	246,294		$	84,290		$	640		$	—		$	331,224

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GLOSSARY OF CERTAIN INDUSTRY TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this Form 10-K. The revisions and additions to the definition section in Rule 4-10(a) of Regulation S-X contained in the SEC’s rule, “Modernization of Oil and Gas Reporting”, are included. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the rule.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of gas.

Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Gross acreage or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Liquidity. The ability to obtain cash quickly either through the conversion of assets or the incurrence of liabilities.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of gas.

Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent. Determined using the ratio of six mcf of natural gas to one barrel of oil.

MMBtu. One million Btus.

MMcf. One million cubic feet of gas.

MMcfe. One million cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six Mcf of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells expressed as whole numbers and fractions of whole numbers.

Primary term lease. An oil and gas property with no existing production, in which Stone has a specific time frame to establish production without losing the rights to explore the property.

Productive well. A well that is found to be mechanically capable of producing hydrocarbons in sufficient quantities that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction technology equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

G-1

Table of Contents

Proved oil and natural gas reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Reasonable certainty is defined as “much more likely to be achieved than not”.

Proved undeveloped reserves (“PUDs”). Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Standardized measure of discounted future net cash flows. The standardized measure represents value-based information about an enterprise’s proved oil and natural gas reserves based on estimates of future cash flows, including income taxes, from production of proved reserves assuming continuation of certain economic and operating conditions. Future cash flows are based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

G-2

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EXHIBIT INDEX



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)).

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†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)).

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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.

*31.1	Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

*31.2	Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

*#32.1	Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.

*99.1	Report of Netherland, Sewell & Associates, Inc.

*101.INS	XBRL Instance Document

*101.SCH	XBRL Taxonomy Extension Schema Document

*101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

*101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

*101.LAB	XBRL Taxonomy Extension Label Linkbase Document

*101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

_________________



*	Filed or furnished herewith.
#	Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
†	Identifies management contracts and compensatory plans or arrangements.