Stone Energy (SGY) 10-K 2014 FY Annual report

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, 2014

or

[   ]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.  [X] Yes  [   ] 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” inRule 12b-2 of the Exchange Act.

Large accelerated filer [X] Accelerated filer [   ]   Non-accelerated filer  [   ] Smaller reporting company [   ]

(Do not check if a 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 $2.6 billion as of June 30, 2014 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

As of February 24, 2015, the registrant had outstanding 55,916,305 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 21, 2015 are incorporated by reference into Part III of this Form 10-K.

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	30
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6.	Selected Financial Data	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
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	48
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

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 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 that 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 Shale in Appalachia. During 2014, we sold certain non-core GOM conventional shelf properties to allow for more focus on these targeted growth areas. As of December 31, 2014, our estimated proved oil and natural gas reserves were approximately 153 Mmboe or 915 Bcfe. 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 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.

Operational Overview

Gulf of Mexico Basin

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 low risk development tie-backs 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 that 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 38% of our estimated proved oil and natural gas reserves at December 31, 2014, on a volume equivalent basis.

Gulf Coast — Deep Gas.  The Gulf Coast deep gas play (prospects below 15,000 feet) provides us with high potential exploration opportunities with existing infrastructure nearby, which shortens the lead time to production. We have made two onshore, south Louisiana, deep gas discoveries and a GOM shelf deep gas discovery. Additionally, we have identified other deep gas opportunities in south Louisiana and the GOM shelf. Our deep gas properties accounted for approximately 2% of our estimated proved oil and natural gas reserves at December 31, 2014, on a volume equivalent basis.

Gulf of Mexico — Conventional Shelf.  In January 2014 and July 2014, we completed sales of our interests in certain non-core properties in the GOM conventional shelf to allow for more focus on our targeted growth areas,

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specifically the GOM deep water, Gulf Coast deep gas and Appalachia. At December 31, 2013, the estimated proved reserves associated with these divested assets represented approximately 9% of our total estimated proved oil and natural gas reserves. Production volumes for the sold properties represented approximately 13% and 24% of our total production volumes for the years ended December 31, 2014 and 2013, respectively. Our remaining GOM conventional shelf properties accounted for approximately 2% of our estimated proved oil and natural gas reserves at December 31, 2014, on a volume equivalent basis. Capital dedicated to the GOM conventional shelf in 2015 will be primarily used for recompletions, improvements to existing infrastructure and required plugging and abandonment operations.

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. During 2006, we began securing leasehold interests in the Appalachia regions of Pennsylvania and West Virginia, and as of December 31, 2014, we held leasehold interests in approximately 90,000 net acres. During 2014, we drilled a total of 38 horizontal Marcellus Shale wells and had 102 operated wells on production at year-end 2014. Additionally, our Utica Shale exploration well in Wetzel County, West Virginia was successful and began producing in December 2014. We expect to secure additional core Marcellus and Utica leasehold interests in West Virginia and drill additional wells, including potential Utica Shale development wells. Our Appalachian properties accounted for approximately 58% of our estimated proved oil and natural gas reserves at December 31, 2014, on a volume equivalent basis.

Business Development

Using a portion of our exploration budget, we seek to acquire seismic data and leasehold interests in undeveloped, onshore, oil-focused plays. The business development effort is focused on providing Stone with exposure to new or unproven plays that could add significant value to the company if successful. As of December 31, 2014, we held leasehold interests in approximately 170,000 net acres (including 131,000 undeveloped acres in Canada). We have budgeted minimal funds in 2015 for onshore exploration projects and new venture opportunities.

Oil and Gas Marketing

Our oil and natural gas production is sold at current market prices under short-term contracts. Shell Trading (US) Company and Phillips 66 Company accounted for approximately 32% and 31%, respectively, of our oil and natural gas revenue generated during the year ended December 31, 2014. 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. SeeItem 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. SeeItem 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

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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.

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.

Certain operations that we conduct are on U.S. federal oil and gas leases, which are administered by the Bureau of Land Management (the “BLM”) and the Bureau of Ocean Energy Management (the “BOEM”). These leases contain relatively standardized terms and require compliance with detailed BLM and BOEM regulations and orders pursuant to various federal laws, including the Outer Continental Shelf Lands Act, which are subject to change by the applicable agency. Many onshore leases contain stipulations limiting activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the times during which activities on the lease may be conducted or the manner in which certain activities may be conducted or, in some cases, may ban any surface activity. 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 BLM or the BOEM, as applicable, 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 (the “OCS”) of the GOM, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. Under certain circumstances, the BLM or the Bureau of Safety and Environmental Enforcement (the “BSEE”), a federal agency created to enforce compliance with safety and environmental rules of the OCS, as applicable, may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and 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

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

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 natural gas liquids (“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

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regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.

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

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

Miscellaneous.  Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by the United States Congress, state regulatory bodies, the BOEM, the BSEE, the FERC and other federal regulatory bodies and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the oil and natural gas industry has been heavily regulated. We can give no assurance that the regulatory approach currently pursued by the BOEM, the BSEE, the FERC or any other state or federal agency will continue indefinitely. We do not anticipate, however, that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect on our financial condition, results of operations or competitive position.

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. 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.

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

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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, in December 2014, the BOEM issued a final rule, effective January 12, 2015, which raises OPA’s damages liability cap from $75 million to $133.65 million. We cannot predict at this time whether the OPA will be amended further or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we could be liable for costs and damages, which costs and damages 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, the EPA finalized modifications to its greenhouse gas reporting rules that would require covered entities to report emissions on an individual greenhouse gas basis. In addition, the EPA has proposed a rule that would expand the agency’s reporting requirements to cover completions and workovers from hydraulically fractured oil wells. Also, the Obama Administration is expected to release a series of new regulations on the oil and gas industry in 2015, including federal standards limiting methane emissions. These new and proposed rules could result in increased compliance costs. We believe that we are in compliance with all greenhouse gas emissions reporting requirements applicable to our operations.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce

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emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or 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 recently 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 proposed rules regarding well stimulation and hydraulic fracturing activities in May 2013 that would require the disclosure of chemicals used during the fracturing process and addresses drilling plans, water management, and wastewater disposal on federal and tribal lands. The BLM expects to issue a final rule sometime in 2015. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards sometime in 2015.

The EPA has also commenced a study of the potential environmental impacts of hydraulic fracturing activities on water resources. The EPA has indicated that it expects to issue its study report sometime in 2015. Also, 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 ongoing or proposed 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, disclosure 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. 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

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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 an analogous state agency. 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 EPA has adopted rules that establish air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA established New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s rules require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and NGLs that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. These rules may require a number of modifications to our operations, including the 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.

We have made, and will continue to make, expenditures in our effort to comply with environmental laws and regulations. We believe that we are in substantial compliance with applicable environmental laws and regulations in effect and that continued compliance with existing requirements will not 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. 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 24, 2015, we had 384 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 (“Exchange Act”), and amendments

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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 May 27, 2014.

Financial Information

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

Forward-Looking Statements

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

Forward-looking statements 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 risked 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;

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

• domestic and worldwide economic conditions;

• the availability of capital on economic terms to fund our capital expenditures and acquisitions;

• our level of indebtedness;

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• 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 replace 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;

• drilling and other operating risks;

• unsuccessful exploration and development drilling activities;

• hurricanes and other weather conditions;

• adverse effects of changes in applicable tax, environmental, derivatives and other regulatory legislation, 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. 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 decline in oil and natural gas prices in the fourth quarter of 2014 has 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, the decline will have 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. A reduction in production could result in a shortfall in our expected cash

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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, 2014, the West Texas Intermediate (“WTI”) crude oil price per barrel ranged from a low of $53.27 to a high of $110.53, and the New York Mercantile Exchange (“NYMEX”) natural gas price per MMBtu ranged from a low of $2.89 to a high of $6.15. The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:

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

• market uncertainty;

• level of consumer product demands;

• hurricanes and other weather conditions;

• domestic and foreign governmental regulations and taxes;

• price and availability of alternative fuels;

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

• actions by the Organization of Petroleum Exporting Countries;

• 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 “Notice to Lessees” (“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

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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. In addition, in August 2014 the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements for companies operating in federal waters. If BOEM were to increase its financial assurance requirements substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition and liquidity.

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. Approximately 42% of our estimated proved reserves at December 31, 2014 (by volume) and 60% of our production during 2014 were associated with our GOM deep water, Gulf Coast deep gas and GOM conventional shelf properties. 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.

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

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discounted future net cash flows from our proved reserves at December 31, 2014 on historical 12-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production and changes in governmental regulations or taxes. At December 31, 2014, approximately 49% 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 make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule 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 high yield debt markets has been significantly limited since the significant decline in commodity prices in the fourth quarter of 2014.

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

An economic crisis could reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas. 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,

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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 (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.

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.

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:

• 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. 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 2015. Upon a redetermination, if borrowings in excess of the revised borrowing capacity are outstanding, we could be forced to repay a portion of our bank debt. Our agreement with the banks allows us one or more of three options to cure a borrowing base deficiency: (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 or (3) arrange to pay the deficiency in six equal monthly installments.

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We may not have sufficient funds to make such repayments. If we are unable to repay our debt out of cash on hand, we could attempt to 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, refinancing or sale of assets will be successfully completed.

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

Approximately 42% of our estimated proved reserves at December 31, 2014 (by volume) and 60% of our production during 2014 were 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. SeeItem 2. Properties – Productive Well and Acreage Data.

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 unavailability or lack of 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.

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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 reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a 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 fourth quarter of 2014 and we recorded a non-cash ceiling test impairment of approximately $351 million for the year ended December 31, 2014. 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,

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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 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) where operations are more difficult and more expensive than in shallower waters. The deep waters of the GOM often lack the physical infrastructure and availability of services present in the shallower waters. As a result, deep water operations may require a significant amount of time between a discovery and the time that we can market the oil and natural gas, increasing the risks involved with these operations.

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 and/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 and/or losses.

Currently, we have general liability insurance coverage with an annual aggregate limit of $825 million on a 100% working interest basis. We no longer purchase physical damage insurance coverage for our platforms for losses resulting from named windstorms. Additionally, we now purchase physical damage insurance coverage for

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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 $300 million per occurrence. Exploratory deep water wells have a coverage limit of up to $600 million per occurrence. Additionally, we maintain $150 million in oil pollution liability coverage, including $70 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 and/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.

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.

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

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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 50% of our estimated production quantities may be hedged for any given year. These arrangements may include futures contracts on the NYMEX or the Intercontinental Exchange. While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

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

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

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

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

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

Currently, some 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.

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

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

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.

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

Potential legislation, if enacted into law, could make significant changes to U.S. federal 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 could become effective. The passage of this legislation or any other similar changes in U.S. federal 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.

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 federal 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, the EPA finalized modifications to its greenhouse gas reporting rules that would require covered entities to report emissions on an individual greenhouse gas basis. In addition, the EPA has proposed a rule that would expand the agency’s reporting requirements to cover completions and workovers from hydraulically fractured oil wells. Also, the

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Obama Administration is expected to release a series of new regulations on the oil and gas industry in 2015, including federal standards limiting methane emissions. These new and proposed rules could result in increased compliance costs. We believe that we are in compliance with all greenhouse gas emissions reporting requirements applicable to our operations.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or 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.

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 functions and equivalent swaps 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, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. 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 proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.

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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’s 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 proposed rules regarding well stimulation and hydraulic fracturing activities in May 2013 that would require the disclosure of chemicals used during the fracturing process and addresses drilling plans, water management, and wastewater disposal on federal and tribal lands. The BLM expects to issue a final rule sometime in 2015. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards sometime in 2015.

The EPA has also commenced a study of the potential environmental impacts of hydraulic fracturing activities on water resources. The EPA has indicated that it expects to issue its study report sometime in 2015. Also, 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 ongoing or proposed 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, disclosure 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. Moreover, some state 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, and also to 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.

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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 24, 2015, our property portfolio consisted of twelve active properties and 99 primary term leases in the GOM Basin (onshore and offshore), three active properties in the Appalachia region and undeveloped acreage in Canada and the Rocky Mountain region. We serve as operator on 88% of our active properties. The properties that we operate accounted for 97% of our year-end 2014 estimated proved reserves. This high operating percentage allows us to better control the timing, selection and costs of our drilling and production activities.

Oil and Natural Gas Reserves

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

Estimates of our proved reserves at December 31, 2014 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

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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 Richard B. Talley, Jr., Vice President and Team Leader, and Patrick L. Higgs, Vice President and Senior Technical Advisor. Mr. Talley is a Registered Professional Engineer in the State of Texas (License No. 102425). Mr. Talley joined NSAI in 2004 after serving as a Senior Engineer at ExxonMobil Production Company. Mr. Talley’s areas of specific expertise include probabilistic assessment of exploration prospects and new discoveries, estimation of oil and gas reserves, and workovers and completions. Mr. Talley received an MBA degree from Tulane University in 2001 and a BS degree in Mechanical Engineering from University of Oklahoma in 1998. Mr. Higgs is a Registered Professional Geophysicist in the State of Texas (License No. 985). Mr. Higgs joined NSAI in 1996 after serving as a Senior Geophysicist at Chevron Exploration & Production Company and Gulf Oil Exploration & Production Company. Mr. Higgs’ areas of specific expertise include oil and gas reserves and probabilistic assessments of new discoveries and exploration prospects and plays. Mr. Higgs received a BS degree from Texas A&M University in 1976. Mr. Talley and Mr. Higgs 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 58% of which are located in the Appalachian region, 38% are located in the GOM deep water and 4% are located in the GOM conventional shelf/Gulf Coast deep gas) as of December 31, 2014. The 2014 average 12-month oil and gas prices net of differentials were $89.46 per Bbl of oil, $36.79 per Bbl of NGLs and $3.68 per Mcf of gas.

Summary of Oil, Natural Gas and NGL Reserves as of December 31, 2014
	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Oil, Natural Gas and NGLs (MMcfe)
Reserves Category:
PROVED
Developed		22,957		13,743		249,924		470,118
Undeveloped		19,440		14,074		243,919		445,006
TOTAL PROVED		42,397		27,817		493,843		915,124

At December 31, 2014, we reported estimated proved undeveloped reserves (“PUDs”) of 445.0 Bcfe, which accounted for 49% of our total estimated proved oil and natural gas reserves. This figure ties to a projected 78 new wells (401.6 Bcfe) and 5 sidetrack wells from existing wellbores (43.4 Bcfe). Our timetable for the five 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 78 PUD locations, we project 13 wells to be drilled in 2015 (143.8 Bcfe); 31 wells in 2016 (116.0 Bcfe); 20 wells in 2017 (107.8 Bcfe); 10 wells in 2018 (24.6 Bcfe) and 4 wells in 2019 (9.4 Bcfe). None of these 78 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 2014.

	Oil, Natural Gas and NGLs (MMcfe)		Future Development Costs (in thousands)
PUDs beginning of year		379,628		$826,531
Revisions of previous estimates		(40,302)		(148,320)
Conversions to proved developed reserves		(81,469)		(122,728)
Additional PUDs added		187,149		339,806
PUDs end of year		445,006		$895,289

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During 2014 we invested approximately $122.7 million to convert 81.5 Bcfe of PUDs to proved developed reserves in the Appalachian region. Additionally, we added approximately 187.1 Bcfe of PUDs to year-end 2014 estimated proved reserves, which were primarily the result of our Appalachia and deep water drilling programs.

The following represents additional information on our significant properties:

Field Name	Location	2014 Production (MMcfe)		December 31, 2014 Estimated Proved Reserves (MMcfe)		Nature of Interest
Mary	Appalachia		28,605		479,375		Working
Pompano(1)	GOM Deep Water		11,666		285,980		Working
Mississippi Canyon Block 109	GOM Deep Water		7,634		55,798		Working
Heather	Appalachia		7,773		46,258		Working
Bayou Hebert	Gulf Coast Deep Gas		7,876		16,570		Working
Ship Shoal Block 113	GOM Shelf		9,756		15,521		Working

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

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 FormEIA-23, “Annual Survey of Oil and Gas Reserves,” as required by Public Law93-275. There are differences between the reserves as reported on FormEIA-23 and as reported herein. The differences are attributable to the fact that FormEIA-23 requires that an operator report the total reserves attributable to wells that it operates, without regard to percentage ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis) or non-operated wells in which it owns an interest.

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Acquisition, Production and Drilling Activity

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

	Year Ended December 31,
	2014		2013		2012
	(In thousands)
Acquisition costs, net of sales of unevaluated properties		$51,590		$79,667		$102,807
Development costs (1)		438,334		378,242		395,555
Exploratory costs		289,890		298,932		81,458
Subtotal		779,814		756,841		579,820
Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements		76,363		79,354		62,664
Total additions to oil and gas properties, net		$856,177		$836,195		$642,484

(1) Includes capitalized asset retirement costs of ($20,305), $54,737 and $95,293 for the years ended December 31, 2014, 2013 and 2012, 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,
	2014		2013		2012
Production:
Oil (MBbls)		5,568		6,894		7,135
Natural gas (MMcf)		47,426		50,129		42,569
NGLs (MBbls)		2,114		1,603		1,163
Oil, natural gas and NGLs (MMcfe)		93,518		101,111		92,357
Average sales prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)	$	91.27	$	103.22	$	105.50
Natural gas (per Mcf)		3.67		3.47		2.65
NGLs (per Bbl)		40.51		37.86		41.70
Oil, natural gas and NGLs (per Mcfe)		8.21		9.36		9.90
Including the cash settlement of effective hedging contracts
Oil (per Bbl)	$	92.69	$	103.73	$	106.70
Natural gas (per Mcf)		3.51		3.80		3.17
NGLs (per Bbl)		40.51		37.86		41.70
Oil, natural gas and NGLs (per Mcfe)		8.21		9.56		10.23
Expenses (per Mcfe):
Lease operating expenses (1)	$	1.89	$	1.99	$	2.33
Transportation, processing and gathering expenses		0.69		0.42		0.24

(1) Includes oil and gas operating costs and major maintenance expense and excludes production and ad valorem 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 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, 2014.

	Year Ended December 31,
FIELD: Mary	2014		2013		2012
Production:
Oil (MBbls)		525		472		340
Natural gas (MMcf)		17,974		12,448		6,815
NGLs (MBbls)		1,247		749		448
Oil, natural gas and NGLs (MMcfe)		28,605		19,774		11,544
Average sales prices:
Oil (per Bbl)		$51.72		$53.76		$54.19
Natural gas (per Mcf)		3.55		3.97		3.27
NGLs (per Bbl)		38.86		35.44		33.94
Oil, natural gas and NGLs (per Mcfe)		4.88		5.13		4.84
Expenses (per Mcfe):
Lease operating expenses (1)		$0.55		$0.42		$1.14
Transportation, processing and gathering expenses		1.50		1.12		1.03

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

	Year Ended December 31,
FIELD: Pompano	2014		2013		2012
Production:
Oil (MBbls)		1,311		1,420		1,266
Natural gas (MMcf)		2,894		2,887		1,980
NGLs (MBbls)		151		162		122
Oil, natural gas and NGLs (MMcfe)		11,666		12,375		10,310
Average sales prices:
Oil (per Bbl)		$92.53		$107.99		$108.65
Natural gas (per Mcf)		3.10		2.49		2.02
NGLs (per Bbl)		41.27		40.65		45.70
Oil, natural gas and NGLs (per Mcfe)		11.70		13.50		14.28
Expenses (per Mcfe):
Lease operating expenses (1)		$2.75		$1.98		$2.01
Transportation, processing and gathering expenses		0.13		0.14		0.09

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

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

	Year Ended December 31,
	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive		5		4.31		2		0.60		1		0.43
Dry		2		0.90		2		0.65		-		-
Development Wells:
Productive		38		33.35		44		28.13		33		23.16
Dry		-		-		1		0.94		3		3.00

During the period beginning January 1, 2015 and ending February 24, 2015, we participated in the drilling of one gross (0.17 net) exploratory well and six gross (5.35 net) development wells.

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, 2014.

	Gross		Net
Productive Wells:
Oil (1):
Deep Water		53		42
Deep Gas		-		-
Conventional Shelf		28		28
Appalachia		-		-
Canada		-		-
Other		-		-
		81		70
Gas:
Deep Water		6		3
Deep Gas		4		1
Conventional Shelf		12		11
Appalachia		128		84
Canada		-		-
Other		-		-
		150		99
Total		231		169
Developed Acres:
Deep Water		60,664		60,664
Deep Gas		6,880		6,878
Conventional Shelf		63,116		63,116
Appalachia		36,297		35,668
Canada		-		-
Other		2,545		2,472
		169,502		168,798

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	Gross		Net
Undeveloped Acres (2):
Deep Water		306,267		306,267
Deep Gas		20,929		20,823
Conventional Shelf		5,694		5,694
Appalachia		67,971		54,679
Canada		131,536		131,424
Other		50,263		36,291
		582,660		555,178
Total		752,162		723,976

(1) 5 gross wells each have dual completions.

(2) Leases covering approximately 7% of our undeveloped gross acreage will expire in 2015, 14% in 2016, 9% in 2017, 24% in 2018, 27% in 2019, 4% in 2020, 2% in 2021, 3% in 2022 and 10% thereafter.

As of December 31, 2014, some of our PUDs were assigned to locations that are currently scheduled to be drilled after lease expiration or are within proposed units that are not fully leased. We employ various steps to extend our legal rights to expiring leases, including extending the term of a lease that has renewal provisions, negotiating lease modifications to extend the lease term, redesigning the well path or negotiating a new lease. If lease negotiations are unsuccessful, Stone may allow the lease to expire on its own terms, and in such cases, may actively pursue a joint venture, purchase, trade or farm-in with the subsequent lessor.

Title to Properties

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

ITEM 3.  LEGAL PROCEEDINGS

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

On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24^th 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 25^th Judicial District Court for the Plaquemines Parish, 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

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and attorney’s fees. Stone engaged counsel and removed the cases to federal court. The plaintiffs opposed removal. The Plaquemines Parish matter was remanded to state court, and it is anticipated that the other matters involving Stone will also be remanded to state court. Stone is actively investigating and evaluating the allegations.

In October 2012, we received a notice from BSEE that it was initiating an enforcement proceeding with respect to an Incident of Non-Compliance observed at our Vermillion Block 255 Platform H in April 2012. We believe that the conditions observed were not actually violations of applicable rules and accordingly initiated discussions with BSEE to resolve the matter. Notwithstanding these discussions, by “Reviewing Officer’s Final Decision” dated July 9, 2013, BSEE assessed a penalty against Stone of $200,000 based on $25,000 per day for eight days of alleged improper venting of gas at the platform. An administrative appeal before IBLA is pending. We do not believe that this proceeding will have a material adverse effect on our financial condition or results of operations.

In August 2013, Kimmeridge Energy Exploration Fund, L.P. (“Kimmeridge”) filed a lawsuit against Stone in the 15^th Judicial District Court in Lafayette Parish, Louisiana seeking damages in the amount of $18,372,819 plus interest, costs and attorney fees. Kimmeridge alleges that (1) Stone failed to pay brokerage costs of $1,118,878 incurred after December 31, 2012 pursuant to a letter of understanding, and (2) Stone owes $17,253,941 to Kimmeridge by virtue of a letter of intent obligating Stone to negotiate in good faith and close an acquisition involving approximately 33,000 net mineral acres in the Illinois basin. The court granted summary judgment in favor of Stone limiting damages at trial on Kimmeridge’s second claim to $1 million. Accordingly, at this time, total maximum exposure to Stone at trial is $2,118,878. Stone continues to vigorously defend against both claims.

On November 17, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. In September 2014, Stone sold its interest in the Loomis No. 1 well site to Southwestern Energy Company (“Southwestern”), and PADEP approved the transfer on November 24, 2014, after Stone’s receipt of the NOV. Stone investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. The PADEP may impose a penalty in this matter, but the amount of that penalty cannot be reasonably estimated at this time. Southwestern is conducting remediation activities at the well site, and Stone continues to monitor those activities.

Also on November 17, 2014, the EPA issued two administrative compliance orders relating, respectively, to Stone’s Conley and Tuttle Impoundment Sites in West Virginia. The EPA compliance orders (1) allege that Stone placed fill material in jurisdictional waters without first obtaining a Clean Water Act permit, and (2) order Stone to submit a wetland and stream delineation report. On December 8, 2014, Stone received a request from the EPA for additional information about the sites. Stone responded to this request and submitted site delineations. The EPA may impose a penalty in this matter, but the amount of that 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
2013
First Quarter		$23.40		$19.44
Second Quarter		24.50		17.34
Third Quarter		33.49		21.95
Fourth Quarter		37.96		30.61
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 (through February 24, 2015)		$18.98		$12.07

On February 24, 2015, the last reported sales price of our common stock on the New York Stock Exchange Composite Tape was $17.08 per share. As of that date, there were 412 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.

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Issuer Purchases of Equity Securities

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Additionally, shares are sometimes withheld from certain employees and nonemployee directors to pay taxes associated with the vesting of restricted stock. 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 2014:

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, 2014	-	$  -	-
November 1 – November 30, 2014	-	-	-
December 1 – December 31, 2014	-	-	-
	-	$  -	-	$	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 2014.

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, 2009 at $18.05 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		2014 Peer Group		S&P 500 Index
12/31/10		123.49		120.92		115.06
12/31/11		146.15		108.57		117.49
12/31/12		113.68		100.42		136.30
12/31/13		191.63		132.59		180.44
12/31/14		93.52		89.88		205.14

The companies that comprised our Peer Group in 2014 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., EPL Oil and Gas, 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 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, 2014. This information is derived from our Consolidated Financial Statements and the notes thereto. SeeItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operationsand Item 8. Financial Statements and Supplementary Data.

	Year Ended December 31,
	2014		2013		2012		2011		2010
Income Statement Data:	(In thousands, except per share amounts)
Operating revenue:
Oil production		$516,104		$715,104		$761,304		$663,958		$417,948
Natural gas production		166,494		190,580		134,739		170,611		210,686
Natural gas liquids production		85,642		60,687		48,498		29,996		27,473
Other operational income		7,951		7,808		3,520		3,938		5,916
Derivative income, net		19,351		-		3,428		1,418		3,265
Total operating revenue		795,542		974,179		951,489		869,921		665,288
Operating expenses:
Lease operating expenses		176,495		201,153		215,003		175,881		150,212
Transportation, processing and gathering expenses		64,951		42,172		21,782		8,958		7,218
Production taxes		12,151		15,029		10,015		9,380		5,808
Depreciation, depletion and amortization		340,006		350,574		344,365		280,020		248,201
Write-down of oil and gas properties		351,192		-		-		-		-
Accretion expense		28,411		33,575		33,331		30,764		34,469
Salaries, general and administrative expenses		66,451		59,524		54,648		40,169		42,759
Franchise tax settlement		-		12,590		-		-		-
Incentive compensation expense		10,361		15,340		8,113		11,600		5,888
Other operational expenses		862		151		267		2,149		5,579
Derivative expense, net		-		2,090		-		-		-
Total operating expenses		1,050,880		732,198		687,524		558,921		500,134
Income (loss) from operations		(255,338)		241,981		263,965		311,000		165,154
Other (income) expenses:
Interest expense		38,855		32,837		30,375		9,289		12,192
Interest income		(574)		(1,695)		(600)		(420)		(1,464)
Other income		(2,332)		(2,799)		(1,805)		(1,942)		(776)
Loss on early extinguishment of debt		-		27,279		1,972		607		1,820
Other expense		274		-		-		-		671
Total other expenses		36,223		55,622		29,942		7,534		12,443
Income (loss) before income taxes		(291,561)		186,359		234,023		303,466		152,711
Income tax provision (benefit)		(102,018)		68,725		84,597		109,134		56,282
Net income (loss)		($189,543)		$117,634		$149,426		$194,332		$96,429
Earnings and dividends per common share:
Basic earnings (loss) per share		($3.60)		$2.36		$3.03		$3.97		$1.99
Diluted earnings (loss) per share		($3.60)		$2.36		$3.03		$3.97		$1.99
Cash dividends declared per share		-		-		-		-		-
Cash Flow Data:
Net cash provided by operating activities		$401,141		$594,205		$509,749		$570,850		$424,794
Net cash used in investing activities		(872,587)		(623,036)		(568,688)		(679,250)		(374,088)
Net cash provided by (used in) financing activities		215,446		80,594		300,014		39,895		(13,043)
Balance Sheet Data (at end of period):
Working capital (deficit)		$226,805		$181,255		$300,348		($13,282)		$30,382
Oil and natural gas properties, net		2,414,002		2,619,696		2,182,095		1,875,048		1,397,809
Total assets		3,018,611		3,248,556		2,776,431		2,165,751		1,679,090
Long-term debt, less current portion		1,041,035		1,027,084		914,126		620,000		575,000
Stone Energy Corporation stockholders’ equity		1,101,603		970,286		872,133		667,829		430,357

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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, 2014. 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. SeeItem 1A. Risk Factors andItem 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 that 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 Shale in Appalachia. During 2014, we sold certain non-core GOM conventional shelf properties to allow for more focus on these targeted growth areas. SeeItem 1. Business – Operational Overview.

2014 Significant Events.

Operational Highlights – In 2014, we drilled two deep water wells at Cardona and initiated production before year-end, less than one year after the first well commenced drilling. Additionally, we drilled a successful deep water exploration well at Amethyst and sanctioned a development plan. In October 2014, we entered into an agreement to contract a deep water drilling rig for our multi-year deep water program in the GOM.

In Appalachia, we drilled 38 wells in the Marcellus shale in 2014 and produced an average of over 100 Mmcfe per day for the year. Our successful Utica Shale exploration well began producing in early December, confirming the play on our existing acreage for future development.

Reserve Growth – Year-end 2014 estimated proved reserves were 915 Bcfe, a 6% increase from 2013 year-end estimated proved reserves. We replaced approximately 252% of production in 2014 from drilling additions and extensions.

Sale of Non-core Properties– In January and July 2014, we completed the sales of our interests in the Cut Off and Clovelly fields (onshore Louisiana) and certain non-core properties in the GOM conventional shelf for total cash consideration of approximately $222.5 million and the assumption of the associated asset retirement obligations of approximately $134.4 million. At December 31, 2013, the estimated proved reserves associated with these assets represented approximately 9% of our total estimated proved oil and natural gas reserves. 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 $26.1 million and the assumption of the associated asset retirement obligations of approximately $3.4 million. At December 31, 2013, the estimated proved reserves associated with these assets represented approximately 2% of our total estimated proved oil and natural gas reserves.

Public Offering of Common Stock –In May 2014, we sold 5,750,000 shares of our common stock in a public offering at a price of $41.00 per share, resulting in net proceeds of approximately $226.0 million after deducting the underwriting discount and offering expenses. The net proceeds are being used for general corporate purposes, which includes development of the Amethyst and Cardona prospects, Utica Shale development and the acquisition of additional Appalachian acreage.

Declining Realized Prices– During the fourth quarter of 2014, we experienced significant declines in oil and natural gas prices as well as widening price differentials in Appalachia. As a result, we incurred ceiling test write-downs of our oil and gas properties.

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2015 Outlook.

Our 2015 capital expenditure budget is approximately $450 million, which assumes planned sales of minority working interests in certain targeted assets. This figure compares with an $895 million capital expenditure budget for 2014 and excludes material acquisitions and capitalized salaries, general and administrative expenses (“SG&A”) and interest. The budget is spread across our major areas of investment, with approximately 75% allocated to the GOM Basin, 8% allocated to Appalachia, 4% allocated to business development, and 13% allocated 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, rig availability, regulatory, non-operator decisions and the sales of working interests in certain targeted assets.

Known Trends and Uncertainties.

Declining Commodity Prices – We have experienced a significant decline in oil and natural gas prices during the second half of 2014 and into 2015. This has resulted in reduced revenue and cash flows and contributed to ceiling test write-downs of our U.S. oil and gas properties at September 30 and December 31, 2014. It has also caused us to reduce our planned capital expenditures budget for 2015. Continued declines or suppression of commodity prices and/or widening negative price differentials (particularly in Appalachia) could result in additional write-downs of our U.S. oil and gas properties in future periods and could severely impact future cash flows, substantially reduce the available borrowings under our bank credit facility and constrain capital budgets beyond 2015.

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 engage in deep water drilling and completion 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 current losses on our statement of operations as well as going concern issues.

Non-U.S. Operations– In April 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. Included in unevaluated oil and gas property costs at December 31, 2014 are $36.6 million of capital expenditures related to our oil and gas property investments in Canada. Under full cost accounting, investments in individual countries represent separate cost centers for the computation of depreciation, depletion and amortization (“DD&A”) as well as for full cost ceiling test evaluations. Given that this is our sole investment in Canada, it is possible that upon a more complete evaluation of this project that some or all of this investment could be recognized as a charge to expense on our statement of operations.

Liquidity and Capital Resources

As of February 24, 2015, we had $480.8 million of availability under our bank credit facility and cash on hand of approximately $216 million, which included $177.6 million of cash that was restricted at December 31, 2014 and released from restrictions on January 27, 2015. Our capital expenditure budget for 2015 has been set at $450 million, which assumes planned sales of minority working interests in certain targeted assets. The budget also excludes material divestitures and acquisitions and capitalized SG&A expenses and interest. Based on our outlook of commodity prices and our estimated production, we expect our 2015 capital expenditures to exceed

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our cash flows from operating activities. We intend to finance our 2015 capital expenditure budget with cash flows from operating activities and cash on hand. To the extent that 2015 cash flows from operating activities and cash on hand are not sufficient to fund capital expenditures, we may borrow under our bank credit facility. Additionally, it is possible that due to further commodity price declines, our inability to successfully execute planned sales of minority working interests or other factors, a portion of our 2015 capital expenditure budget may need to be financed from other sources. Although we have no current plans to access the public or private markets for purposes of capital, we may consider such funding sources to provide additional capital.

We are subject to evaluations by the BOEM for continuation of our current exemption from supplemental bonding on abandonment obligations. It is possible that future agency action or failure to meet the required levels of compliance as a result of declining commodity prices could result in a loss of exemption and could have an adverse impact on our liquidity should we be required to post bonds or letters of credit.

Cash Flow and Working Capital.  Net cash flows from operating activities totaled $401.1 million during the year ended December 31, 2014 compared to $594.2 million and $509.7 million during the years ended December 31, 2013 and 2012, respectively.

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 natural 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 natural 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 natural 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 natural gas properties of $48.8 million. Net cash used in investing activities totaled $568.7 million during the year ended December 31, 2012, which primarily represents our investment in oil and natural gas properties of $555.9 million and our investment in fixed and other assets of $13.4 million.

Net cash provided by financing activities totaled $215.4 million for 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 new 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 2017 Notes. Net cash provided by financing activities totaled $300.0 million during the year ended December 31, 2012. In 2012, we received $291.1 million of net proceeds from the issuance of the 2017 Convertible Notes and $40.1 million of proceeds from the Sold Warrants, and used $70.8 million for the cost of the Purchased Call Options (seeNotes to Consolidated Financial Statements – NOTE 11 – Long-Term Debt). Additionally, we received $293.2 million of net proceeds from the issuance of the 2022 Notes. During 2012, we used $200.7 million for the redemption of our 6 ³⁄₄% Senior Subordinated Notes due 2014 (the “2014 Notes”). During the year ended December 31, 2012, we had $25.0 million of borrowings and $70.0 million of repayments of borrowings under our bank credit facility.

We had working capital of $226.8 million at December 31, 2014.

Capital Expenditures.  During the year ended December 31, 2014, additions to oil and gas property costs of $856.2 million included $53.2 million of lease and property acquisition costs, $30.6 million of capitalized SG&A expenses (inclusive of incentive compensation) and $45.7 million of capitalized interest. These investments were financed with cash on hand, cash flows from operating activities and the net proceeds from the May 2014 equity offering.

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

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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 million and was reaffirmed at $500 million in October 2014. As of December 31, 2014 and February 24, 2015, we had no 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 $480.8 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. The bank credit facility is guaranteed by our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”).

The borrowing base under the bank credit facility is redetermined semi-annually, usually 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 in May 2015. The bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage and grant a security interest in their oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from their 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 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, 2014, our Consolidated Funded Debt to consolidated EBITDA ratio was 2.26 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 12.03 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, 2014.

Common Stock Offering.  In May 2014, we sold 5,750,000 shares of our common stock in a public offering at a price of $41.00 per share, resulting in net proceeds of approximately $226.0 million after deducting the underwriting discount and offering expenses. The net proceeds are being used for general corporate purposes, which includes development of the Amethyst and Cardona prospects, Utica Shale development and the acquisition of additional Appalachian acreage.

Share Repurchase Program.  On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Through December 31, 2014, 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, 2014, 2013 or 2012.

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

Safety Performance

We measure 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. 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 for safety monitoring in the GOM. Our TRIR for the last three calendar years was as follows:

Year Ended December 31,	TRIR Performance	TRIR Goal
2014	0.00	0.50
2013	0.47	0.50
2012	0.45	0.55

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 TRIR.

Results of Operations

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. SeeItem 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%)
NGLs 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%)

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	Year Ended December 31,
	2014		2013		Variance		% Change
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.

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 ($224.8 million after taxes). 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, 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 5,568,000 Bbls compared to 6,894,000 Bbls 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 2,114,000 Bbls compared to 1,603,000 Bbls 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.

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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 on 2014 derivative instruments 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 is attributable to higher 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.

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 8  ⁵⁄₈% Senior Notes due 2017.

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.

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2013 Compared to 2012. 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. SeeItem 2. Properties – Oil and Natural Gas Reserves.

	Year Ended December 31,
	2013		2012		Variance		% Change
Production:
Oil (MBbls)		6,894		7,135		(241)		(3%)
Natural gas (MMcf)		50,129		42,569		7,560		18%
NGLs (MBbls)		1,603		1,163		440		38%
Oil, natural gas and NGLs (MMcfe)		101,111		92,357		8,754		10%
Revenue data (in thousands):(1)
Oil revenue		$715,104		$761,304		($46,200)		(6%)
Natural gas revenue		190,580		134,739		55,841		41%
NGL revenue		60,687		48,498		12,189		25%
Total oil, natural gas and NGL revenue		$966,371		$944,541		$21,830		2%
Average prices:
Prior to the cash settlement of effective hedging contracts
Oil (per Bbl)		$103.22		$105.50		($2.28)		(2%)
Natural gas (per Mcf)		3.47		2.65		0.82		31%
NGLs (per Bbl)		37.86		41.70		(3.84)		(9%)
Oil, natural gas and NGLs (per Mcfe)		9.36		9.90		(0.54)		(6%)
Including the cash settlement of effective hedging contracts
Oil (per Bbl)		$103.73		$106.70		($2.97)		(3%)
Natural gas (per Mcf)		3.80		3.17		0.63		20%
NGLs (per Bbl)		37.86		41.70		(3.84)		(9%)
Oil, natural gas and NGLs (per Mcfe)		9.56		10.23		(0.67)		(7%)
Expenses (per Mcfe):
Lease operating expenses		$1.99		$2.33		($0.34)		(15%)
Transportation, processing and gathering expenses		0.42		0.24		0.18		75%
Salaries, general and administrative expenses (2)		0.59		0.59		-		N/A
DD&A expense on oil and gas properties		3.43		3.69		(0.26)		(7%)
Estimated Proved Reserves at December 31:
Oil (MBbls)		43,827		44,918		(1,091)		(2%)
Natural gas (MMcf)		460,766		395,374		65,392		17%
NGLs (MBbls)		23,297		18,066		5,231		29%
Oil, natural gas and NGLs (MMcfe)		863,513		773,285		90,228		12%

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

(2) Excludes incentive compensation expense.

Net Income.  For the year ended December 31, 2013, we reported net income totaling $117.6 million, or $2.36 per share, compared to net income for the year ended December 31, 2012 of $149.4 million, or $3.03 per share. All per share amounts are on a diluted basis.

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

Production.  During the year ended December 31, 2013, total production volumes increased to 101.1 Bcfe compared to 92.4 Bcfe produced during the comparable 2012 period, representing a 10% increase. Oil production during the year ended December 31, 2013 totaled approximately 6,894,000 Bbls compared to 7,135,000 Bbls produced during the year ended December 31, 2012. Natural gas production totaled 50.1 Bcf during the year ended December 31, 2013 compared to 42.6 Bcf produced during the comparable 2012 period. NGL production

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during the year ended December 31, 2013 totaled approximately 1,603,000 Bbls compared to 1,163,000 Bbls produced during the comparable 2012 period. During the fourth quarter of 2013, ten new wells in the Mary field and two new wells in the Heather field were brought online. The third well in the La Cantera field was placed on production during the second quarter of 2013.

Prices.  Prices realized during the year ended December 31, 2013 averaged $103.73 per Bbl of oil, $3.80 per Mcf of natural gas and $37.86 per Bbl of NGLs, or 7% lower, on an Mcfe basis, than 2012 average realized prices of $106.70 per Bbl of oil, $3.17 per Mcf of natural gas and $41.70 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 gas prices. 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. During the year ended December 31, 2012, effective hedging transactions increased our average realized natural gas price by $0.52 per Mcf and increased our average realized oil price by $1.20 per Bbl.

Revenue.  Oil, natural gas and NGL revenue increased 2% to $966.4 million for the year ended December 31, 2013 from $944.5 million for the year ended December 31, 2012. The increase was attributable to a 10% increase in production quantities on a gas equivalent basis, which was partially offset by a 7% decrease in average realized prices.

Expenses.  Lease operating expenses for the years ended December 31, 2013 and 2012 totaled $201.2 million and $215.0 million, respectively. On a unit of production basis, lease operating expenses were $1.99 per Mcfe and $2.33 per Mcfe for the years ended December 31, 2013 and 2012, respectively. The decrease in lease operating expenses in 2013 was primarily attributable to a decrease in insurance and major maintenance expenses.

Transportation, processing and gathering expenses for the years ended December 31, 2013 and 2012 totaled $42.2 million and $21.8 million, respectively. The increase was attributable to higher gas and NGL volumes and short term blending fees in Appalachia, as well as higher GOM pipeline fees.

DD&A expense on oil and gas properties for the year ended December 31, 2013 totaled $346.8 million, or $3.43 per Mcfe, compared to DD&A expense of $341.1 million, or $3.69 per Mcfe, for the year ended December 31, 2012.

For the years ended December 31, 2013 and 2012, SG&A expenses (exclusive of incentive compensation) totaled $59.5 million and $54.6 million, respectively. The increase in SG&A expenses in 2013 was primarily the result of increased staffing and compensation adjustments (including share-based compensation). Partially offsetting this increase was a reimbursement of $1.6 million of legal fees relating to the settlement of litigation in a prior period. Included in SG&A expenses in 2012 was a $1.0 million management fee for transition services related to the Pompano field acquisition.

For the years ended December 31, 2013 and 2012, incentive compensation expense totaled $15.3 million and $8.1 million, respectively. These amounts related to incentive compensation bonuses calculated based on the achievement of certain strategic objectives for each fiscal year.

During the year ended December 31, 2013, we executed a settlement with the Louisiana Department of Revenue (“LDR”) in the amount of $13 million relating to claims asserted in litigation, as well as assessments proposed by the LDR for franchise and income taxes alleged to be due by Stone for the tax years 1999 through 2009, including claims for interest thereon.

Interest expense for the year ended December 31, 2013 totaled $32.8 million, net of $46.9 million of capitalized interest, compared to interest expense of $30.4 million, net of $37.7 million of capitalized interest, for

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the year ended December 31, 2012. The increase in interest expense was primarily the result of interest associated with the 2022 Notes issued in November 2012 and November 2013, and the 2017 Convertible Notes issued in March 2012. Partially offsetting these increases was a decrease in interest expense as a result of the redemption in December 2012 of our 2014 Notes.

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, 2014 (in thousands):

	Total		Less than 1 Year		1-3 Years		4-5 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
Interest and commitment fees (1)		486,348		65,203		127,786		118,984		174,375
Asset retirement obligations including accretion		798,397		96,506		74,073		30,272		597,546
Rig commitments		290,321		99,365		180,770		10,186		-
Seismic data commitments		62,339		27,650		34,689		-		-
Operating lease obligations		11,979		1,416		3,095		2,533		4,935
Total Contractual Obligations and Commitments		$2,724,384		$290,140		$720,413		$161,975		$1,551,856

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

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. SeeItem 1. Business — Forward-Looking Statementsand 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 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, 2014 and 2013, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities.

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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 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. Instruments that qualify for cash flow hedge accounting treatment with contemporaneous documentation are 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. Additionally,

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monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value, and changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities.

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

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

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

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

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

• effectiveness and estimated fair value of derivative positions;

• classification of unevaluated property costs;

• capitalized general and administrative costs and interest;

• estimates of fair value in business combinations;

• current and deferred income taxes; 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 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 core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. The standard is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early application is not permitted. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. 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.

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. Assuming a 10% decline in realized oil and natural gas prices, including the effects of hedging contracts, we estimate our diluted net loss per share for 2014 would have increased approximately $0.94 per share. In order to manage our exposure to oil and natural gas price declines, we occasionally 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 with various counterparties for a portion of our expected 2015 and 2016 oil and natural gas production from the Gulf Coast Basin. Our fixed-price oil swap settlements are based on an average of the NYMEX closing price for WTI crude oil during the entire calendar month. Our fixed-price gas

46

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. Our fixed-price swap contracts are with The Toronto-Dominion Bank, Barclays Bank PLC, The Bank of Nova Scotia, Bank of America and Natixis.

The following table illustrates our hedging positions for calendar years 2015 and 2016 as of February 24, 2015:

	Fixed-Price Swaps (NYMEX)
	Natural Gas				Oil
	Daily Volume (MMBtus/d)		Swap Price ($/MMBtu)		Daily Volume (Bbls/d)		Swap     Price     ($/Bbl)
2015		10,000		4.005		1,000		89.00
2015		10,000		4.120		1,000		90.00
2015		10,000		4.150		1,000		90.25
2015		10,000		4.165		1,000		90.40
2015		10,000		4.220		1,000		91.05
2015		10,000		4.255		1,000		93.28
2015						1,000		93.37
2015						1,000		94.85
2015						1,000		95.00
2016		10,000		4.110		1,000		90.00
2016		10,000		4.120

Our hedging policy provides that not more than 50% of our estimated production quantities can be hedged for any given year without the consent of our board of directors. We believe that our hedging positions, taking into consideration the board-approved divestiture of our non-core GOM conventional shelf properties, have hedged approximately 54% of our estimated 2015 production from estimated proved reserves and 12% of our estimated 2016 production from estimated proved reserves.

Interest Rate Risk.  We had total debt outstanding of $1,075 million at December 31, 2014, all of which bears interest at fixed rates. The $1,075 million of fixed-rate debt is comprised of $300 million face value of the 2017 Convertible Notes and $775 million of the 2022 Notes.

Our bank credit facility is subject to an adjustable interest rate. SeeItem 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, 2014. If we borrow funds under our bank credit facility, we may be subject to increased sensitivity to interest rate movements.

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.

47

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2014 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, 2014 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, 2014. 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, 2014. 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, 2014.

48

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, 2014, 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, 2014, 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, 2014 and 2013, 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, 2014 and our report dated February 26, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 26, 2015

49

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 2015 Annual Meeting of Stockholders to be held on May 21, 2015. 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 2015 Annual Meeting of Stockholders to be held on May  21, 2015.

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 2015 Annual Meeting of Stockholders to be held on May 21, 2015.

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 2015 Annual Meeting of Stockholders to be held on May 21, 2015.

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 2015 Annual Meeting of Stockholders to be held on May 21, 2015.

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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, 2014 and 2013

Consolidated Statement of Operations for the three years ended December 31, 2014, 2013 and 2012

Consolidated Statement of Comprehensive Income (Loss) for the three years ended December 31, 2014, 2013 and 2012

Consolidated Statement of Cash Flows for the three years ended December 31, 2014, 2013 and 2012

Consolidated Statement of Changes in Stockholders’ Equity for the three years ended December 31, 2014, 2013 and 2012

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, 2012 (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	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)).

51

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)).
†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 (incorporated by reference to Appendix A to the Registrant’s Definitive Proxy Statement on Schedule 14A for Stone’s 2009 Annual Meeting of Stockholders (File No. 001-12074)).
†10.3	First Amendment to Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-12074)).
†10.4	Stone Energy Corporation Revised (2005) Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.11 to the Registrant’s Annual Report on Form10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.5	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)).
†10.6	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)).
†10.7	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)).
†10.8	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)).

52

†10.9	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)).
†10.10	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)).
†10.11	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)).
10.12	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)).
10.13	$900,000,000 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)).
10.14	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)).

53

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 Form8-K filed March 6, 2012 (File No. 001-12074)).
10.25	Purchase and Sale Agreement (as amended) between Stone Energy Offshore, L.L.C. and Stone Energy Corporation, collectively as the seller, and Talos Energy Offshore LLC, as buyer, dated June 27, 2014 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed August 1, 2014 (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.
*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
*99.1	Report of Netherland, Sewell & Associates, Inc.

* 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.

54

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, 2015	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 David H. Welch	President, Chief Executive Officer and Chairman of the Board (principal executive officer)	February 26, 2015
/s/ Kenneth H. Beer Kenneth H. Beer	Executive Vice President and Chief Financial Officer (principal financial officer)	February 26, 2015
/s/ Karl D. Meche Karl D. Meche	Director of Accounting and Treasurer (principal accounting officer)	February 26, 2015
/s/ George R. Christmas George R. Christmas	Director	February 26, 2015
/s/ B.J. Duplantis B.J. Duplantis	Director	February 26, 2015
/s/ Peter D. Kinnear Peter D. Kinnear	Director	February 26, 2015
/s/ David T. Lawrence David T. Lawrence	Director	February 26, 2015
/s/ Robert S. Murley Robert S. Murley	Director	February 26, 2015
/s/ Richard A. Pattarozzi Richard A. Pattarozzi	Director	February 26, 2015
/s/ Donald E. Powell Donald E. Powell	Director	February 26, 2015
/s/ Kay G. Priestly Kay G. Priestly	Director	February 26, 2015
/s/ Phyllis M. Taylor Phyllis M. Taylor	Director	February 26, 2015

55

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheet as of December 31, 2014 and 2013	F-3
Consolidated Statement of Operations for the years ended December 31, 2014, 2013 and 2012	F-4
Consolidated Statement of Comprehensive Income (Loss) for the years ended December  31, 2014, 2013 and 2012	F-5
Consolidated Statement of Cash Flows for the years ended December 31, 2014, 2013 and 2012	F-6
Consolidated Statement of Changes in Stockholders’ Equity for the years ended December  31, 2014, 2013 and 2012	F-7
Notes to Consolidated Financial Statements	F-8

F-1

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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Stone Energy Corporation’s internal control over financial reporting as of December 31, 2014, 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, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 26, 2015

F-2

STONE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands)

	December 31,
Assets	2014		2013
Current assets:
Cash and cash equivalents		$74,488		$331,224
Restricted cash		177,647		-
Accounts receivable		120,359		171,971
Fair value of derivative contracts		139,179		4,549
Current income tax receivable		7,212		7,366
Deferred taxes		-		31,710
Inventory		3,709		3,723
Other current assets		8,118		1,874
Total current assets		530,712		552,417
Oil and gas properties, full cost method of accounting:
Proved		8,817,268		7,804,117
Less: accumulated depreciation, depletion and amortization		(6,970,631)		(5,908,760)
Net proved oil and gas properties		1,846,637		1,895,357
Unevaluated		567,365		724,339
Other property and equipment, net of accumulated depreciation of $24,091 and $21,748, respectively		32,340		26,178
Fair value of derivative contracts		14,333		1,378
Other assets, net of accumulated depreciation and amortization of $8,478 and $5,768, respectively		27,224		48,887
Total assets		$3,018,611		$3,248,556
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors		$132,629		$195,677
Undistributed oil and gas proceeds		23,232		37,029
Accrued interest		9,022		9,022
Deferred taxes		20,119		-
Fair value of derivative contracts		-		7,753
Asset retirement obligations		69,400		67,161
Other current liabilities		49,505		54,520
Total current liabilities		303,907		371,162
Long-term debt		1,041,035		1,027,084
Deferred taxes		286,343		390,693
Asset retirement obligations		247,009		435,352
Fair value of derivative contracts		-		470
Other long-term liabilities		38,714		53,509
Total liabilities		1,917,008		2,278,270
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 54,884,542 and 48,750,533 shares, respectively		549		488
Treasury stock (16,582 shares, at cost)		(860)		(860)
Additional paid-in capital		1,633,307		1,397,885
Accumulated deficit		(614,708)		(425,165)
Accumulated other comprehensive income (loss)		83,315		(2,062)
Total stockholders’ equity		1,101,603		970,286
Total liabilities and stockholders’ equity		$3,018,611		$3,248,556

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

F-3

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

	Year Ended December 31,
	2014		2013		2012
Operating revenue:
Oil production		$516,104		$715,104		$761,304
Natural gas production		166,494		190,580		134,739
Natural gas liquids production		85,642		60,687		48,498
Other operational income		7,951		7,808		3,520
Derivative income, net		19,351		-		3,428
Total operating revenue		795,542		974,179		951,489
Operating expenses:
Lease operating expenses		176,495		201,153		215,003
Transportation, processing and gathering expenses		64,951		42,172		21,782
Production taxes		12,151		15,029		10,015
Depreciation, depletion and amortization		340,006		350,574		344,365
Write-down of oil and gas properties		351,192		-		-
Accretion expense		28,411		33,575		33,331
Salaries, general and administrative expenses		66,451		59,524		54,648
Franchise tax settlement		-		12,590		-
Incentive compensation expense		10,361		15,340		8,113
Other operational expenses		862		151		267
Derivative expense, net		-		2,090		-
Total operating expenses		1,050,880		732,198		687,524
Income (loss) from operations		(255,338)		241,981		263,965
Other (income) expenses:
Interest expense		38,855		32,837		30,375
Interest income		(574)		(1,695)		(600)
Other income		(2,332)		(2,799)		(1,805)
Other expense		274		-		-
Loss on early extinguishment of debt		-		27,279		1,972
Total other expenses		36,223		55,622		29,942
Income (loss) before income taxes		(291,561)		186,359		234,023
Provision (benefit) for income taxes:
Current		159		(10,904)		15,022
Deferred		(102,177)		79,629		69,575
Total income taxes		(102,018)		68,725		84,597
Net income (loss)		($189,543)		$117,634		$149,426
Basic earnings (loss) per share		($3.60)		$2.36		$3.03
Diluted earnings (loss) per share		($3.60)		$2.36		$3.03
Average shares outstanding		52,721		48,693		48,319
Average shares outstanding assuming dilution		52,721		48,735		48,361

The accompanying notes are an integral part of this statement.

F-4

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

	Year Ended December 31,
	2014		2013		2012
Net income (loss)		($189,543)		$117,634		$149,426
Other comprehensive income (loss), net of tax effect:
Derivatives		88,178		(30,228)		6,965
Foreign currency translation		(2,801)		(667)		-
Comprehensive income (loss)		($104,166)		$86,739		$156,391

The accompanying notes are an integral part of this statement.

F-5

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2014		2013		2012
Cash flows from operating activities:
Net income (loss)		($189,543)		$117,634		$149,426
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		340,006		350,574		344,365
Write-down of oil and gas properties		351,192		-		-
Accretion expense		28,411		33,575		33,331
Deferred income tax (benefit) provision		(102,177)		79,629		69,575
Settlement of asset retirement obligations		(56,409)		(83,854)		(65,567)
Non-cash stock compensation expense		11,325		10,347		8,699
Excess tax benefits		-		(156)		(949)
Non-cash derivative (income) expense		(18,028)		2,239		(509)
Loss on early extinguishment of debt		-		27,279		1,972
Non-cash interest expense		16,661		16,219		13,085
Change in current income taxes		158		2,767		10,618
(Increase) decrease in accounts receivable		51,611		(4,683)		(55,871)
(Increase) decrease in other current assets		(6,244)		1,752		(2,836)
Decrease in inventory		-		583		436
Increase (decrease) in accounts payable		(3,419)		402		5,101
Increase (decrease) in other current liabilities		(19,152)		42,451		(10,426)
Other		(3,251)		(2,553)		9,299
Net cash provided by operating activities		401,141		594,205		509,749
Cash flows from investing activities:
Investment in oil and gas properties		(927,247)		(663,299)		(555,855)
Proceeds from sale of oil and gas properties, net of expenses		242,914		48,821		403
Sale of fixed assets		-		-		134
Investment in fixed and other assets		(10,182)		(6,816)		(13,370)
Change in restricted funds		(178,072)		(1,742)		-
Net cash used in investing activities		(872,587)		(623,036)		(568,688)
Cash flows from financing activities:
Proceeds from bank borrowings		-		-		25,000
Repayments of bank borrowings		-		-		(70,000)
Proceeds from issuance of senior convertible notes		-		-		300,000
Deferred financing costs of senior convertible notes		-		-		(8,855)
Proceeds from sold warrants		-		-		40,170
Payments for purchased call options		-		-		(70,830)
Proceeds from issuance of senior notes		-		489,250		300,000
Net proceeds from issuance of common stock		225,999		-		-
Deferred financing costs		(3,371)		(9,065)		(11,966)
Redemption of senior notes		-		(396,014)		-
Redemption of senior subordinated notes		-		-		(200,681)
Excess tax benefits		-		156		949
Net payments for share-based compensation		(7,182)		(3,733)		(3,773)
Net cash provided by financing activities		215,446		80,594		300,014
Effect of exchange rate changes on cash		(736)		(65)		-
Net change in cash and cash equivalents		(256,736)		51,698		241,075
Cash and cash equivalents, beginning of year		331,224		279,526		38,451
Cash and cash equivalents, end of year		$74,488		$331,224		$279,526
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized		($14,076)		($29,883)		($20,150)
Cash (paid) refunded for income taxes		(1)		13,670		(4,405)

The accompanying notes are an integral part of this statement.

F-6

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, 2011		$481		($860)		$1,338,565		($692,225)		$21,868		$667,829
Net income		-		-		-		149,426		-		149,426
Adjustment for fair value accounting of derivatives, net of tax		-		-		-		-		6,965		6,965
Exercise of stock options and vesting of restricted stock		3		-		(3,776)		-		-		(3,773)
Amortization of stock compensation expense		-		-		12,792		-		-		12,792
Net tax impact from stock option exercises and restricted stock vesting		-		-		814		-		-		814
Convertible notes offering		-		-		38,080		-		-		38,080
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

The accompanying notes are an integral part of this statement.

F-7

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 that 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 Shale in Appalachia. During 2014, we sold our non-core GOM conventional shelf properties to allow for more focus on these targeted growth areas. 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. and Stone Energy Canada, U.L.C. All intercompany balances have been eliminated.

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, the purchase price allocation on properties acquired, 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, 2014 and 2013, 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”). SeeNote 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

F-8

discount as interest expense. Additionally, the hedging transactions meet the criteria for classification as equity transactions and were recorded as such.

ASC 260 provides that for contracts that may be settled in common stock or in cash at the election of the entity or the holder, the determination of whether the contract shall be reflected in the computation of diluted earnings per share should be made based on the facts available each period. It is presumed that the contract will be settled in common stock and therefore potential dilution be determined using the if-converted method. However, this presumption may be overcome if past experience or a stated policy provides a reasonable basis to believe that the contract will be settled partially or wholly in cash. Because it is management’s stated intent to redeem the principal amount of the notes in cash, we have used the treasury stock method for determining potential dilution of the notes in our diluted earnings per share computation in accordance with ASC 260.

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

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

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

Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and excluding cash flows related to

F-9

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.

Production Revenue:

We recognize production revenue under the entitlement 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 2012, 2013 and 2014, 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

F-10

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. Instruments that qualify as a hedging instrument, with contemporaneous documentation, are recorded as either an asset or liability, measured at fair value, with subsequent changes in the derivative’s fair value 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 gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value, and 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 recognize 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 — 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,
	2014		2013		2012
Income (numerator):
Basic:
Net income (loss)		($189,543)		$117,634		$149,426
Net income attributable to participating securities		-		(2,817)		(2,984)
Net income (loss) attributable to common stock - basic		($189,543)		$114,817		$146,422
Diluted:
Net income (loss)		($189,543)		$117,634		$149,426
Net income attributable to participating securities		-		(2,815)		(2,982)
Net income (loss) attributable to common stock - diluted		($189,543)		$114,819		$146,444
Weighted average shares (denominator):
Weighted average shares - basic		52,721		48,693		48,319
Dilutive effect of stock options		-		42		42
Weighted average shares - diluted		52,721		48,735		48,361
Basic earnings (loss) per share		($3.60)		$2.36		$3.03
Diluted earnings (loss) per share		($3.60)		$2.36		$3.03

F-11

All outstanding stock options were considered antidilutive during the year ended December 31, 2014 (205,000 shares) because we had a net loss for such period. 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 and 347,000 shares during the years ended December 31, 2013 and 2012, respectively.

During the years ended December 31, 2014, 2013 and 2012, approximately 384,000, 358,000 and 316,000 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 (seeNote 3 – Common Stock Offering).

Because it is management’s stated intention to redeem the principal amount of our 2017 Convertible Notes (seeNote 11 – Long-Term Debt) in cash, we have used the treasury method for determining dilution in the diluted earnings per share computation. For the year ended December 31, 2014, there was no dilutive effect on the diluted earnings per share computation as we had a net loss for such year. For the years ended December 31, 2013 and 2012, the average price of our common stock was less than the effective conversion price for such notes, resulting in no dilutive effect on the diluted earnings per share computation for such years. For the years ended December 31, 2014, 2013 and 2012, the average price of our common stock was less than the strike price of the Sold Warrants (as defined inNote 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 inNote 11 – Long-Term Debt), such call options are antidilutive and therefore, were not included in the calculation of diluted earnings per share.

NOTE 3 — COMMON STOCK OFFERING:

In May 2014, we sold 5,750,000 shares of our common stock in a public offering at a price of $41.00 per share, resulting in net proceeds of approximately $225,999 after deducting the underwriting discount and offering expenses.

NOTE 4 — ACCOUNTS RECEIVABLE:

In our capacity as operator for ourco-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,
	2014		2013
Other co-venturers		$16,291		$13,904
Trade		60,263		134,622
Unbilled accounts receivable		33,052		22,001
Other		10,753		1,444
Total accounts receivable		$120,359		$171,971

F-12

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 gas revenue during the indicated periods:

	Year Ended December 31,
	2014			2013			2012
Conoco, Inc.		(a	)		(a	)		13	%
Phillips 66 Company		31	%		35	%		18	%
Shell Trading (US) Company		32	%		33	%		41	%

(a)    Less than 10 percent.

The maximum amount of credit risk exposure at December 31, 2014 relating to these customers was $31,929.

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 gas production.

Production and Reserve Volumes- Unaudited

Approximately 42% of our estimated proved reserves at December 31, 2014 and 60% of our production during 2014 were associated with our GOM deep water, conventional shelf and deep gas properties. Approximately 58% of our estimated proved reserves at December 31, 2014 and 40% of our production during 2014 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 sales 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. At December 31, 2013, the estimated proved reserves associated with these assets represented approximately 9% of our total estimated proved oil and natural gas reserves. 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. At December 31, 2013, the estimated proved reserves associated with these assets represented approximately 2% of our total estimated proved oil and natural gas reserves. 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 in like-kind replacement property as defined under Section 1031 of the

F-13

Internal Revenue Code, and are included in our balance sheet as restricted cash at December 31, 2014. Compliance with provisions under the Qualified Trust Agreement and Exchange Agreement provides 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.

In October 2013, we completed the sale of our interest in the Weeks Island field for cash consideration of approximately $42,957 and the assumption of the associated asset retirement obligation of approximately $9,245. The sale was accounted for as a reduction of net proved oil and gas properties with no gain or loss recognized.

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.

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 gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments are recorded in our balance sheet at fair value, and 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.

We have entered into fixed-price swaps with various counterparties for a portion of our expected 2015 and 2016 oil and natural gas production from the Gulf Coast Basin. Our fixed-price oil swap 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. Our fixed-price swap contracts are with The Toronto-Dominion Bank, Barclays Bank PLC, The Bank of Nova Scotia, Bank of America and Natixis.

F-14

The following table illustrates our derivative positions for calendar years 2015 and 2016 as of February 24, 2015:

	Fixed-Price Swaps (NYMEX)
	Natural Gas				Oil
	Daily Volume (MMBtus/d)		Swap Price ($/MMBtu)		Daily Volume (Bbls/d)		Swap Price ($/Bbl)
2015		10,000		4.005		1,000		89.00
2015		10,000		4.120		1,000		90.00
2015		10,000		4.150		1,000		90.25
2015		10,000		4.165		1,000		90.40
2015		10,000		4.220		1,000		91.05
2015		10,000		4.255		1,000		93.28
2015						1,000		93.37
2015						1,000		94.85
2015						1,000		95.00
2016		10,000		4.110		1,000		90.00
2016		10,000		4.120

All of our derivative instruments at December 31, 2013 and 2012 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 (seeNote 6 – Divestitures), that GOM natural gas production would be sufficient to cover the GOM volumes hedged. Accordingly, we discontinued hedge accounting for such contracts. Natural gas contracts no longer qualifying as cash flow hedges included three contracts for the month of August 2014, four contracts for the months of September through December 2014 and three contracts for the months of 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 are not 100% correlative to changes in the underlying price basis indicative in the derivative contract. At December 31, 2014, we had accumulated other comprehensive income of $86,783, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of December 31, 2014. We believe that approximately $77,991, net of tax, 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, 2014 and 2013:

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			$  -

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Fair Value of Derivatives Qualifying as Hedging Instruments at December 31, 2013
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of derivative contracts		$4,549	Current liabilities: Fair value of derivative contracts		$7,753
	Long-term assets: Fair value of derivative contracts		1,378	Long-term liabilities: Fair value of derivative contracts		470
			$5,927			$8,223

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, 2014, 2013 and 2012:

Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations for the Years Ended December 31, 2014, 2013 and 2012
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
	2014			2014			2014
Commodity contracts		$136,097	Operating revenue - oil/gas production		$526	Derivative income, net		$5,721
Total		$136,097			$526			$5,721
	2013			2013			2013
Commodity contracts		($26,945)	Operating revenue - oil/gas production		$20,289	Derivative expense, net		($2,090)
Total		($26,945)			$20,289			($2,090)
	2012			2012			2012
Commodity contracts		$41,209	Operating revenue - oil/gas production		$30,326	Derivative income, net		$3,428
Total		$41,209			$30,326			$3,428

(a) For the year ended December 31, 2014, effective hedging contracts increased oil revenue by $7,929 and decreased gas revenue by $7,403. For the year ended December 31, 2013, effective hedging contracts increased oil revenue by $3,520 and increased gas revenue by $16,769. For the year ended December 31, 2012, effective hedging contracts increased oil revenue by $8,546 and increased gas revenue by $21,780.

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, 2014. All of our derivatives at December 31, 2013 qualified as hedging instruments.

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

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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 year ended December 31, 2014:

Amount of Gain Recognized in Derivative Income
Description	Year Ended     December 31, 2014
Commodity contracts:
Cash settlements		$1,484
Change in fair value		12,146
Total gains on non-qualifying hedges		$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, 2014, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset. The following presents the potential impact of the rights of offset associated with our recognized assets and liabilities at December 31, 2013:

	As Presented Without Netting		Effects of Netting		With Effects of Netting
Current assets: Fair value of derivative contracts		$4,549		($4,043)		$506
Long-term assets: Fair value of derivative contracts		1,378		(274)		1,104
Current liabilities: Fair value of derivative contracts		(7,753)		4,043		(3,710)
Long-term liabilities: Fair value of derivative contracts		(470)		274		(196)

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, 2014 and 2013, 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. For a more detailed description of our derivative instruments, seeNote 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.

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The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014:

	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		$  -
	Fair Value Measurements at December 31, 2014
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative contracts		$  -		$  -		$  -		$  -
Total		$  -		$  -		$  -		$  -

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2013:

	Fair Value Measurements at December 31, 2013
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)		$8,248		$8,248		$  -		$  -
Derivative contracts		5,927		-		5,927		-
Total		$14,175		$8,248		$5,927		$  -
	Fair Value Measurements at December 31, 2013
Liabilities	Total		Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Derivative contracts		$8,223		$  -		$8,223		$  -
Total		$8,223		$  -		$8,223		$  -

The fair value of cash and cash equivalents approximated book value at December 31, 2014 and 2013. As of December 31, 2014 and 2013, the fair value of the liability component of the 2017 Convertible Notes was approximately $252,587 and $260,377, respectively. As of December 31, 2014 and 2013, the fair value of the 7 ¹⁄₂% Senior Notes due 2022 (the “2022 Notes”) was approximately $664,563 and $814,719, 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 (seeNote 11 – Long-Term Debt) at inception and at December 31, 2014 and 2013. 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.

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NOTE 9 — ASSET RETIREMENT OBLIGATIONS:

The change in our asset retirement obligations during the years ended December 31, 2014, 2013 and 2012 is set forth below:

	Year Ended December 31,
	2014		2013		2012
Asset retirement obligations as of the beginning of the year, including current portion		$502,513		$488,302		$425,779
Liabilities incurred		28,606		19,043		3,869
Liabilities settled		(55,839)		(79,695)		(67,641)
Liabilities assumed		-		-		15,263
Divestment of properties		(137,801)		(9,245)		(7,563)
Accretion expense		28,411		33,575		33,331
Revision of estimates		(49,481)		50,533		85,264
Asset retirement obligations as of the end of the year, including current portion		$316,409		$502,513		$488,302

NOTE 10 — INCOME TAXES:

An analysis of our deferred taxes follows:

	As of December 31,
	2014		2013
Tax effect of temporary differences:
Net operating loss carryforwards		$99,615		$24,437
Oil and gas properties – full cost		(476,367)		(576,393)
Asset retirement obligations		113,907		180,905
Stock compensation		5,603		5,537
Hedges		(54,439)		826
Accrued incentive compensation		6,185		9,189
Other		(966)		(3,484)
		($306,462)		($358,983)

We estimate that we have approximately $159, ($10,904) and $15,022 of current federal income tax expense (benefit) for the years ended December 31, 2014, 2013 and 2012, respectively. We have a $7,212 current income tax receivable at December 31, 2014.

For tax reporting purposes, net operating loss carryforwards totaled approximately $281,240 at December 31, 2014. If not utilized, such carryforwards would begin expiring in 2033 and would completely expire by the year 2034. In addition, we had approximately $920 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized.

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

	Year Ended December 31,
	2014	2013	2012
Income tax expense computed at the statutory federal income tax rate	35.0%	35.0%	35.0%
State taxes	1.0	1.0	1.0
IRC Sec. 162(m) limitation	(0.5)	0.8	0.6
Tax deficits on stock compensation	(0.2)	-	-
Other	(0.3)	0.1	(0.5)
Effective income tax rate	35.0%	36.9%	36.1%

Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to $49,601, ($17,003) and $3,918 for the years ended December 31, 2014, 2013 and 2012, respectively.

As of December 31, 2014 and 2013, we had no unrecognized tax benefits.

The tax years 2011 through 2013 remain subject to examination by major tax jurisdictions.

NOTE 11 — LONG-TERM DEBT:

Long-term debt consisted of the following at:

	December 31,
	2014		2013
1 3⁄4% Senior Convertible Notes due 2017		$266,035		$252,084
7 1⁄2% Senior Notes due 2022		775,000		775,000
Bank debt		-		-
Total long-term debt		$1,041,035		$1,027,084

Bank Debt

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 2014. As of December 31, 2014 and February 24, 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. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. The bank credit facility is guaranteed by our only material subsidiary, Stone Offshore.

The borrowing base under the bank credit facility is redetermined semi-annually, usually 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 a reduction in our borrowing base were to fall below any outstanding balances under the bank credit facility plus any outstanding letters of credit, our agreement with the banks allows us one or more of three options to cure the borrowing base deficiency: (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

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such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so or (3) arrange to pay the deficiency in six equal monthly installments.

The bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from their 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, 2014, our Consolidated Funded Debt to consolidated EBITDA ratio was 2.26 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 12.03 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, 2014.

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, at our election, based on an initial conversion rate of 23.4449 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, 2014, our closing share price was $16.88. 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 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

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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, at our election. 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.

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, 2014, the carrying amount of the liability component of the 2017 Convertible Notes was $266,035 and $1,750 had been accrued in connection with the March 1, 2015 interest payment. 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 $12,959 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 2017 Convertible Notes. During each of the years ended December 31, 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 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

F-22

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. We also may redeem up to 35% of the 2022 Notes prior to November 15, 2015 with cash proceeds from certain equity offerings at a redemption price of 107.500% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. 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, 2014, $7,266 had been accrued in connection with the May 15, 2015 interest payment.

Deferred Financing Cost and Interest Cost

Other assets at December 31, 2014 and 2013 included approximately $12,415 and $11,754, respectively, of deferred financing costs, net of accumulated amortization. These costs related primarily to the issuance of the 2017 Convertible Notes, the 2022 Notes and the bank credit facility. 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 bank credit facility are being amortized over the term of the bank credit facility.

Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2014, 2013 and 2012 was $84,577, $79,697 and $68,031 respectively.

NOTE 12 — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):

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

	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/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/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)

In 2012, the only component of accumulated other comprehensive income related to our cash flow hedges. Changes in accumulated other comprehensive income for the year ended December 31, 2012 were as follows:

	Cash Flow Hedges
For the Year Ended December 31, 2012
Beginning balance, net of tax		$21,868
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives		41,209
Income tax effect		(14,836)
Net of tax		26,373
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production		30,326
Income tax effect		(10,918)
Net of tax		19,408
Other comprehensive income, net of tax		6,965
Ending balance, net of tax		$28,833

NOTE 13 — SHARE-BASED COMPENSATION:

Under the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, as amended from time to time (the “2009 Plan”), we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such 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. Stock options to all 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

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subsequent to award. In addition, the 2009 Plan provides that shares available under the 2009 Plan may be granted as restricted stock. Restricted stock typically vests over a one- to 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, 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. For the year ended December 31, 2012, we incurred $13,399 of share-based compensation, of which $13,308 related to restricted stock issuances and $91 related to stock option grants, and of which a total of approximately $4,288 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, 2014, 2013 or 2012.

A summary of stock option activity under the 2009 Plan 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		-		-		-		-

Exercise prices for stock options outstanding at December 31, 2014 range from $6.97 to $53.20.

A summary of stock option activity under the 2009 Plan 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

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A summary of stock option activity under the 2009 Plan during the year ended December 31, 2012 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		438,394		$38.76
Granted		-		-
Exercised		-		-
Forfeited		(4,200)		35.54
Expired		(22,400)		34.25
Options outstanding, end of period		411,794		39.04		2.8 years		$766
Options exercisable, end of period		378,004		41.00		2.5 years		459
Options unvested, end of period		33,790		17.17		5.4 years		307

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, 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. During the year ended December 31, 2012, we issued 670,818 shares of restricted stock valued at $21,085.

A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2014, 2013 and 2012 is as follows (amounts in table represent actual values):

	2014				2013				2012
	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		1,258,053		$23.92		1,108,874		$27.56		923,740		$20.08
Issuances		674,904		36.44		848,498		20.61		670,818		31.43
Lapse of restrictions		(598,796)		24.57		(534,041)		25.45		(462,141)		18.29
Forfeitures		(31,055)		30.19		(165,278)		26.43		(23,543)		26.10
Restricted stock outstanding, end of period		1,303,106		$29.95		1,258,053		$23.92		1,108,874		$27.56

As of December 31, 2014, there was $22,354 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 1.8 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 ($54), ($884) and $814 in 2014, 2013 and 2012, respectively. Additionally, during 2014, $609 of tax deficits were charged to income tax expense.

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NOTE 14 — SHARE REPURCHASE PROGRAM:

On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100,000. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Through December 31, 2014, 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, 2014, 2013 and 2012.

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 2025. 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, 2014 were as follows:

2015	$1,416
2016	1,571
2017	1,524
2018	1,339
2019	1,194
2020	1,206
2021	879
2022	779
2023	792
2024	805
2025	474

Payments related to our lease obligations for the years ended December 31, 2014, 2013 and 2012 were approximately $966, $597 and $894, respectively.

Other Commitments

We are contingently liable to surety insurance companies in the amount of $78,070 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 $352,660 to be incurred over the next four 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 waters, with higher amounts of up to

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$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. We do not anticipate that we will experience any difficulty in continuing to satisfy the BOEM’s requirements for demonstrating financial responsibility under the OPA and the BOEM’s regulations.

Litigation

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.

In August 2013, Kimmeridge Energy Exploration Fund, L.P. (“Kimmeridge”) filed a lawsuit against Stone in the 15^th Judicial District Court in Lafayette Parish, Louisiana seeking damages in the amount of approximately $18,373 plus interest, costs and attorney fees. Kimmeridge alleges that (1) Stone failed to pay brokerage costs of $1,119 incurred after December 31, 2012 pursuant to a letter of understanding, and (2) Stone owes $17,254 to Kimmeridge by virtue of a letter of intent obligating Stone to negotiate in good faith and close an acquisition involving approximately 33,000 net mineral acres in the Illinois basin. The court granted summary judgment in favor of Stone limiting damages at trial on Kimmeridge’s second claim to $1,000. Accordingly, at this time, total exposure to Stone at trial is $2,119. Stone continues to vigorously defend against both claims. We estimate the potential range of loss upon resolution of this matter to be between $0 and $2,119.

NOTE 16 — EMPLOYEE BENEFIT PLANS:

We have entered into deferred compensation and disability agreements with certain of our officers and former officers. The benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2014, the liability for such vested benefits was approximately $858 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 $10,361, $15,340, and $8,113, net of amounts capitalized, for each of the years ended December 31, 2014, 2013 and 2012, respectively, related to incentive compensation bonuses to be paid under the revised plan.

Stock Incentive Plans

At the 2011 Annual Meeting of Stockholders, the stockholders approved the First Amendment (the “First Amendment”) to the 2009 Plan. The First Amendment increased the number of shares of our common stock that Stone may issue under the 2009 Plan, and the number of shares of our common stock that may be issued under the 2009 Plan through incentive stock options by 2,800,000 shares, effective May 20, 2011. 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 incentive stock options, options that are not qualified as incentive stock options and restricted stock awards or any combination as is best suited to the circumstances of the particular employee or nonemployee director, except that only employees may receive incentive stock options. The 2009 Plan eliminates 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 granted under the 2009 Plan

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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. Stock options to all 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. Restricted stock grants typically vest in one to three years at the discretion of the Compensation Committee of our board of directors. At December 31, 2014, we had approximately 1,563,967 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 directions 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, 2014, 2013 and 2012, Stone contributed $1,989, $1,793 and $1,759, 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. To date there have been no matching 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, 2014 and 2013, plan assets of $8,425 and $8,248, 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 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 “key employee” for purposes of Section 409A of the Code, payment will be

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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 six months; and (iii) a pro-rated portion of the employee’s targeted bonus for the year. 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 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, 2014 and 2013, our oil and gas properties were located in the United States and Canada. At December 31, 2012, all of our oil and gas properties were located in the United States.

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Costs Incurred

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

	Year Ended December 31,
	2014			2013		2012
Oil and gas properties – United States, proved and unevaluated:
Balance, beginning of year		$8,517,873			$7,692,261		$7,049,777
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties		44,634			70,903		102,807
Exploratory costs		270,850			297,113		81,458
Development costs (1)		438,334	��		378,242		395,555
Salaries, general and administrative costs		33,975			32,815		25,318
Interest		45,722			46,860		37,656
Less: overhead reimbursements		(3,334)			(321)		(310)
Total costs incurred during the year, net of divestitures		830,181			825,612		642,484
Balance, end of year		$9,348,054			$8,517,873		$7,692,261
Accumulated DD&A:
Balance, beginning of year		($5,908,760)			($5,510,166)		($5,174,729)
Provision for DD&A		(335,987)			(346,827)		(341,096)
Write-down of oil and gas properties		(351,192)			-		-
Sale of proved properties		(374,692)			(51,767)		5,659
Balance, end of year		($6,970,631)			($5,908,760)		($5,510,166)
Net capitalized costs – United States, proved and unevaluated		$2,377,423			$2,609,113		$2,182,095
DD&A per Mcfe		$3.59			$3.43		$3.69
(1) Includes capitalized asset retirement costs of ($20,305), $54,737 and $95,293, respectively.
Costs incurred during the year (expensed):
Lease operating expenses		$176,495			$201,153		$215,003
Transportation, processing and gathering expenses		64,951			42,172		21,782
Production taxes		12,151			15,029		10,015
Accretion expense		28,411			33,575		33,331
Expensed costs – United States		$282,008			$291,929		$280,131

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 September 30, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $47,130 based on twelve month average prices, net of applicable differentials, of $94.94 per barrel of oil, $4.19 per Mcf of natural gas and $41.33 per barrel of natural gas liquids. At December 31, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $304,062 based on twelve month average prices, net of applicable differentials, of $89.46 per barrel of oil, $3.68 per Mcf of natural gas and $36.79 per barrel of natural gas liquids. The September 30 and December 31, 2014 write-downs were increased by $29,001 and $13,342, respectively, as a result of hedges.

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

	Year Ended December 31,
Unevaluated oil and gas properties – United States:	2014		2013		2012
Net costs incurred (evaluated) during year:
Acquisition costs		($42,384)		$30,271		$9,739
Exploration costs		(186,308)		188,830		(1,209)
Capitalized interest		45,722		46,860		37,656
		($182,970)		$265,961		$46,186

During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. The following table discloses certain financial data relative to our oil and gas activities located in Canada:

	Year Ended December 31,
	2014		2013
Oil and gas properties – Canada, unevaluated:
Balance, beginning of year		$10,583		$  -
Costs incurred during the year (capitalized):
Acquisition costs		6,956		8,764
Exploratory costs		19,040		1,819
Total costs incurred during the year		25,996		10,583
Balance, end of year, unevaluated		$36,579		$10,583

The following table discloses financial data associated with unevaluated costs (United States and Canada) at December 31, 2014:

	Balance as of December 31, 2014		Net Costs Incurred During the Year Ended December 31,
			2014		2013		2012		2011 and prior
Acquisition costs		$285,896		$7,330		$82,990		$24,736		$170,840
Exploration costs		167,510		66,512		78,684		5,318		16,996
Capitalized interest		113,959		22,352		36,137		21,993		33,477
Total unevaluated costs		$567,365		$96,194		$197,811		$52,047		$221,313

Approximately 108 specifically identified drilling projects are included in unevaluated costs at December 31, 2014 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, 2014, 2013 and 2012 totaled $45,722, $46,860 and $37,656, respectively.

Proved Oil and Natural Gas Quantities

Our estimated net proved oil and natural gas reserves at December 31, 2014 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.

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The following table sets forth an analysis of the estimated quantities of net proved oil (including condensate), natural gas and natural gas liquids (“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, 2014, 2013 and 2012 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, 2011		45,655		4,405		325,479		625,839
Revisions of previous estimates		(1,559)		9,349		(26,694)		20,050
Extensions, discoveries and other additions		3,681		4,856		131,408		182,633
Purchase of producing properties		4,336		619		8,168		37,895
Sale of reserves		(60)		-		(418)		(775)
Production		(7,135)		(1,163)		(42,569)		(92,357)
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
Estimated proved developed reserves:
as of December 31, 2012		29,005		8,593		210,956		436,540
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
Estimated proved undeveloped reserves:
as of December 31, 2012		15,913		9,473		184,418		336,745
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

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

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 relates 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).

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Year Ended December 31, 2012.  Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (162 Bcfe) and our deep gas development project at LaCantera (17 Bcfe). Purchase of producing properties relates to our acquisition of an additional interest in the Pompano field.

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, 2014. 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 2014 average historical 12-month oil and 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 gas. The 2013 average 12-month oil and 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 gas. The 2012 average 12-month oil and gas prices, net of applicable differentials, were $101.20 per Bbl of oil, $38.23 per Bbl of NGLs and $2.68 per Mcf of 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,
	2014		2013		2012
Future cash inflows		$  6,635,751		$  7,040,928		$  6,295,455
Future production costs		(2,413,004)		(2,062,657)		(1,946,426)
Future development costs		(1,511,687)		(1,431,101)		(1,241,531)
Future income taxes		(609,516)		(884,637)		(799,007)
Future net cash flows		2,101,544		2,662,533		2,308,491
10% annual discount		(682,752)		(977,531)		(794,632)
Standardized measure of discounted future net cash flows		$  1,418,792		$  1,685,002		$  1,513,859

	Changes in Standardized Measure Year Ended December 31,
	2014		2013		2012
Standardized measure at beginning of year		$1,685,002		$1,513,859		$1,542,962
Sales and transfers of oil, gas and NGLs produced, net of production costs		(486,232)		(708,017)		(697,741)
Changes in price, net of future production costs		(864,118)		229,425		(380,841)
Extensions and discoveries, net of future production and development costs		549,649		155,592		178,272
Changes in estimated future development costs, net of development costs incurred during the period		203,026		28,684		212,329
Revisions of quantity estimates		(27,495)		281,558		76,450
Accretion of discount		222,009		202,087		207,292
Net change in income taxes		209,323		(28,084)		22,947
Purchases of reserves in-place		-		-		276,389
Sales of reserves in-place		(152,787)		15,531		2,480
Changes in production rates due to timing and other		80,415		(5,633)		73,320
Net increase (decrease) in standardized measure		(266,210)		171,143		(29,103)
Standardized measure at end of year		$1,418,792		$1,685,002		$1,513,859

F-34

NOTE 18 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED:

The results of operations by quarter are as follows:

	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	) (a)		(286,147) (b)
Net income (loss)		25,943		4,444		(29,415	) (a)		(190,515) (b)
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)

	2013 Quarter Ended
	March 31		June 30		September 30		December 31
Operating revenue		$233,732		$245,877		$256,685		$239,253
Income from operations		72,828		69,525		62,422		37,206 (c)
Net income		40,758		39,022		36,102		1,752 (c)	(d)
Basic earnings per share		$0.82		$0.78		$0.72		$0.04
Diluted earnings per share		$0.82		$0.78		$0.72		$0.04

(a) Includes a write-down of oil and gas properties of $47,130 before income tax effect ($30,163 net of income tax effect).

(b) Includes a write-down of oil and gas properties of $304,062 before income tax effect ($194,600 net of income tax effect).

(c) Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).

(d) Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

NOTE 19 – RECENTLY ISSUED ACCOUNTING STANDARDS:

In May 2014, the Financial Accounting Standards Board 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 core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. The standard is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early application is not permitted. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. 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.

F-35

NOTE 20 – GUARANTOR FINANCIAL STATEMENTS:

Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents consolidating financial information as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 on an issuer (parent company), Guarantor Subsidiary, Non-Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2014

(In thousands)

	Parent		Guarantor Subsidiary		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		20,857		1,360		5,007		-		27,224
Investment in subsidiary		1,050,546		-		41,638		(1,092,184)		-
Total assets		$2,457,388		$1,574,087		$83,415		($1,096,279)		$3,018,611
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		1,041,035		-		-		-		1,041,035
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		1,355,785		565,318		-		(4,095)		1,917,008
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		$2,457,388		$1,574,087		$83,415		($1,096,279)		$3,018,611

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

F-36

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2013

(In thousands)

	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents		$246,294		$84,290		$640		$-		$331,224
Accounts receivable		74,887		97,128		-		(44)		171,971
Fair value of derivative contracts		-		4,549		-		-		4,549
Current income tax receivable		7,366		-		-		-		7,366
Deferred taxes *		8,659		23,051		-		-		31,710
Inventory		3,440		283		-		-		3,723
Other current assets		1,874		-		-		-		1,874
Total current assets		342,520		209,301		640		(44)		552,417
Oil and gas properties, full cost method:
Proved		1,309,527		6,494,590		-		-		7,804,117
Less: accumulated DD&A		(459,932)		(5,448,828)		-		-		(5,908,760)
Net proved oil and gas properties		849,595		1,045,762		-		-		1,895,357
Unevaluated		325,113		388,643		10,583		-		724,339
Other property and equipment, net		26,178		-		-		-		26,178
Fair value of derivative contracts		-		1,378		-		-		1,378
Other assets, net		45,410		1,349		2,128		-		48,887
Investment in subsidiary		747,472		-		12,711		(760,183)		-
Total assets		$2,336,288		$1,646,433		$26,062		($760,227)		$3,248,556
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors		$173,147		$22,530		$44		($44)		$195,677
Undistributed oil and gas proceeds		34,386		2,643		-		-		37,029
Accrued interest		9,022		-		-		-		9,022
Fair value of derivative contracts		-		7,753		-		-		7,753
Asset retirement obligations		-		67,161		-		-		67,161
Other current liabilities		53,682		838		-		-		54,520
Total current liabilities		270,237		100,925		44		(44)		371,162
Long-term debt		1,027,084		-		-		-		1,027,084
Deferred taxes *		10,227		380,466		-		-		390,693
Asset retirement obligations		4,945		430,407		-		-		435,352
Fair value of derivative contracts		-		470		-		-		470
Other long-term liabilities		53,509		-		-		-		53,509
Total liabilities		1,366,002		912,268		44		(44)		2,278,270
Commitments and contingencies
Stockholders’ equity:
Common stock		488		-		-		-		488
Treasury stock		(860)		-		-		-		(860)
Additional paid-in capital		1,397,885		1,309,563		27,403		(1,336,966)		1,397,885
Accumulated deficit		(425,165)		(574,003)		(52)		574,055		(425,165)
Accumulated other comprehensive loss		(2,062)		(1,395)		(1,333)		2,728		(2,062)
Total stockholders’ equity		970,286		734,165		26,018		(760,183)		970,286
Total liabilities and stockholders’ equity		$2,336,288		$1,646,433		$26,062		($760,227)		$3,248,556

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

F-37

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2014

(In thousands)

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

F-38

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2013

(In thousands)

	Parent		Guarantor Subsidiary		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		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

F-39

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2012

(In thousands)

	Parent		Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Operating revenue:
Oil production		$26,149		$735,155		$  -		$  -		$761,304
Natural gas production		34,331		100,408		-		-		134,739
Natural gas liquids production		15,264		33,234		-		-		48,498
Other operational income		2,766		397		357		-		3,520
Derivative income, net		-		3,428		-		-		3,428
Total operating revenue		78,510		872,622		357		-		951,489
Operating expenses:
Lease operating expenses		19,914		195,105		(16)		-		215,003
Transportation, processing and gathering expenses		12,049		9,733		-		-		21,782
Production taxes		3,330		6,685		-		-		10,015
Depreciation, depletion, amortization		63,022		281,152		191		-		344,365
Accretion expense		561		32,513		257		-		33,331
Salaries, general and administrative		54,641		7		-		-		54,648
Incentive compensation expense		8,113		-		-		-		8,113
Other operational expenses		173		94		-		-		267
Total operating expenses		161,803		525,289		432		-		687,524
Income (loss) from operations		(83,293)		347,333		(75)		-		263,965
Other (income) expenses:
Interest expense		30,446		(71)		-		-		30,375
Interest income		(285)		(315)		-		-		(600)
Other income		(144)		(1,661)		-		-		(1,805)
Loss on early extinguishment of debt		1,972		-		-		-		1,972
(Income) loss from investment in subsidiaries		(223,555)		75		-		223,480		-
Total other (income) expenses		(191,566)		(1,972)		-		223,480		29,942
Income (loss) before taxes		108,273		349,305		(75)		(223,480)		234,023
Provision (benefit) for income taxes:
Current		15,022		-		-		-		15,022
Deferred		(56,175)		125,750		-		-		69,575
Total income taxes		(41,153)		125,750		-		-		84,597
Net income (loss)		$149,426		$223,555		($75)		($223,480)		$149,426
Comprehensive income (loss)		$156,391		$223,555		($75)		($223,480)		$156,391

F-40

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2014

(In thousands)

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

F-41

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2013

(In thousands)

	Parent		Guarantor Subsidiary		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
Non-cash (income) loss from investment in subsidiaries		(214,983)		-		26		214,957		-
Change in current income taxes		2,767		-		-		-		2,767
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

F-42

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2012

(In thousands)

	Parent			Guarantor Subsidiary		Non- Guarantor Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities:			��
Net income (loss)		$149,426			$223,555		($75)		($223,480)		$149,426
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		63,022			281,152		191		-		344,365
Accretion expense		561			32,513		257		-		33,331
Deferred income tax provision (benefit)		(56,175)			125,750		-		-		69,575
Settlement of asset retirement obligations		-			(65,567)		-		-		(65,567)
Non-cash stock compensation expense		8,699			-		-		-		8,699
Excess tax benefits		(949)			-		-		-		(949)
Non-cash derivative income		-			(509)		-		-		(509)
Loss on early extinguishment of debt		1,972			-		-		-		1,972
Non-cash interest expense		13,085			-		-		-		13,085
Non-cash (income) loss from investment in subsidiaries		(223,555)			75		-		223,480		-
Change in current income taxes		10,618			-		-		-		10,618
Change in intercompany receivables/payables		275,819			(275,125)		(694)		-		-
(Increase) decrease in accounts receivable		(22,750)			(33,345)		224		-		(55,871)
Increase in other current assets		(2,836)			-		-		-		(2,836)
Decrease in inventory		436			-		-		-		436
Increase (decrease) in accounts payable		5,348			(208)		(39)		-		5,101
Decrease in other current liabilities		(5,311)			(5,115)		-		-		(10,426)
Other		10,960			(1,661)		-		-		9,299
Net cash provided by (used in) operating activities		228,370			281,515		(136)		-		509,749
Cash flows from investing activities:
Investment in oil and gas properties		(324,542)			(231,313)		-		-		(555,855)
Proceeds from sale of oil and gas properties, net of expenses		403			-		-		-		403
Sale of fixed assets		134			-		-		-		134
Investment in fixed and other assets		(13,370)			-		-		-		(13,370)
Net cash used in investing activities		(337,375)			(231,313)		-		-		(568,688)
Cash flows from financing activities:
Proceeds from bank borrowings		25,000			-		-		-		25,000
Repayment of bank borrowings		(70,000)			-		-		-		(70,000)
Proceeds from issuance of senior convertible notes		300,000			-		-		-		300,000
Deferred financing costs of senior convertible notes		(8,855)			-		-		-		(8,855)
Proceeds from sold warrants		40,170			-		-		-		40,170
Payments for purchased call options		(70,830)			-		-		-		(70,830)
Proceeds from issuance of senior notes		300,000			-		-		-		300,000
Deferred financing costs		(11,966)			-		-		-		(11,966)
Redemption of senior subordinated notes		(200,681)			-		-		-		(200,681)
Excess tax benefits		949			-		-		-		949
Net payments for share-based compensation		(3,773)			-		-		-		(3,773)
Net cash provided by financing activities		300,014			-		-		-		300,014
Net change in cash and cash equivalents		191,009			50,202		(136)		-		241,075
Cash and cash equivalents, beginning of period		37,389			926		136		-		38,451
Cash and cash equivalents, end of period		$228,398			$51,128		$  -		$  -		$279,526

F-43

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 termsstructural featureandstratigraphic 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.

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.

G-1

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.

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

EXHIBIT INDEX

Exhibit Number	Description
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, 2012 (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	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)).
†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 (incorporated by reference to Appendix A to the Registrant’s Definitive Proxy Statement on Schedule 14A for Stone’s 2009 Annual Meeting of Stockholders (File No. 001-12074)).
†10.3	First Amendment to Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-12074)).

†10.4	Stone Energy Corporation Revised (2005) Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.11 to the Registrant’s Annual Report onForm 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.5	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)).
†10.6	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)).
†10.7	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)).
†10.8	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)).
†10.9	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)).
†10.10	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)).
†10.11	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)).
10.12	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)).
10.13	$900,000,000 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)).
10.14	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 Form8-K filed March 6, 2012 (File No. 001-12074)).
10.25	Purchase and Sale Agreement (as amended) between Stone Energy Offshore, L.L.C. and Stone Energy Corporation, collectively as the seller, and Talos Energy Offshore LLC, as buyer, dated June 27, 2014 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed August 1, 2014 (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.
*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
*99.1	Report of Netherland, Sewell & Associates, Inc.

* 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.