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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF

1934

For the fiscal year ended December 31, 2012

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” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x Accelerated filer  ̈

Non-accelerated filer  ̈ (Do not check if a smaller reporting company) Smaller reporting company  ̈

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

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $1.2 billion as of June 30, 2012 (based on the last

reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

As of February 21, 2013, the registrant had outstanding 49,259,243 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 23, 2013 are incorporated by reference into Part III of this Form 10-K.
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TABLE OF CONTENTS

 Page No.

PART I 

Item 1. Business 3 

Item 1A. Risk Factors 9 

Item 1B. Unresolved Staff Comments 19 

Item 2. Properties 19 

Item 3. Legal Proceedings 23 

Item 4. Mine Safety Disclosures 24 

PART II 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 24 

Item 6. Selected Financial Data 27 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 28 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 37 

Item 8. Financial Statements and Supplementary Data 38 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 39 

Item 9A. Controls and Procedures 39 

Item 9B. Other Information 41 

PART III 

Item 10. Directors, Executive Officers and Corporate Governance 41 

Item 11. Executive Compensation 42 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 42 

Item 13. Certain Relationships and Related Transactions, and Director Independence 42 

Item 14. Principal Accounting Fees and Services 42 

PART IV 

Item 15. Exhibits, Financial Statement Schedules 43 

Index to Financial Statements F-1 

Glossary of Certain Industry Terms G-1 

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PART I

This section highlights information that is discussed in more detail in the remainder of the document. Throughout this document, we make

statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section 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 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 Coast Basin since our incorporation in 1993 and have established a technical and operational expertise in

this area. We have expanded our reserve base outside of the conventional shelf of the Gulf of Mexico (“GOM”) and into the more prolific reserve basins of the

GOM deep water and Gulf Coast deep gas, as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia. As of

December 31, 2012, our estimated proved oil and natural gas reserves were approximately 773 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.

Strategy and Operational Overview

Our business strategy is to leverage cash flow generated from existing assets to maintain relatively stable GOM shelf production, profitably grow gas

reserves and production in price-advantaged basins such as Appalachia and the Gulf Coast Basin, and profitably grow oil reserves and production in the deep

water GOM and onshore oil areas.

Gulf of Mexico – Deep Water. We believe that the deep water of the GOM is an attractive area to explore and operate, even though it involves high risk,

high costs and substantial lead time to develop infrastructure. We have made two significant acquisitions that included two deep water platforms, producing

reserves and numerous leases. We have also utilized subsea tie-backs in the deep water on new drill wells that require less capital than a deep water facility. We

have made a significant investment in seismic data and leasehold interests and have assembled a technical team with prior geological, geophysical and

engineering experience in the deep water arena to evaluate potential exploration, development and acquisition opportunities. Our deep water properties accounted

for approximately 34% of our estimated proved oil and natural gas reserves at December 31, 2012 on a volume equivalent basis.

Appalachia. During 2006, we began securing leasehold interests in the Appalachia regions of Pennsylvania and West Virginia. As of December 31,

2012, we had leasehold interests in approximately 93,000 net acres. During 2012, we drilled a total of 23 horizontal Marcellus shale wells and fractured 24

wells. We expect to add leasehold interests and drill additional wells to further expand our interests in Appalachia. Our Appalachian properties accounted for

approximately 44% of our estimated proved oil and natural gas reserves at December 31, 2012 on a volume equivalent basis.

South Louisiana Gulf of Mexico – Deep Gas. The deep gas play 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 have identified other

deep gas opportunities in south Louisiana. Additionally, our current property base in the GOM also contains multiple deep shelf exploration opportunities,

which are defined as prospects below 15,000 feet. Our deep shelf gas properties accounted for approximately 4% of our estimated proved oil and natural gas

reserves at December 31, 2012 on a volume equivalent basis.

Gulf of Mexico – Conventional Shelf (Including Onshore Louisiana). We seek to generate cash flow from existing reserves and establish

additional proved reserves through the drilling of new wells, workovers and recompletions of existing wells and the application of other techniques designed to

provide production to help mitigate some of the natural decline of the GOM conventional shelf. Our GOM conventional shelf properties accounted for

approximately 18% of our estimated proved oil and natural gas reserves at December 31, 2012 on a volume equivalent basis.

Onshore Oil. We maintain working interests in several undeveloped plays, which totaled approximately 92,000 net acres as of December 31, 2012. We

have budgeted funds in 2013 for new venture opportunities. Our onshore oil properties accounted for less than 1% of our estimated proved oil and natural gas

reserves at December 31, 2012 on a volume equivalent basis.

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Oil and Gas Marketing

Our oil and natural gas production is sold at current market prices under short-term contracts. Shell Trading (US) Company, Phillips 66 Company

and Conoco, Inc. accounted for approximately 41%, 18% and 13%, respectively, of our oil and natural gas revenue generated during the year ended

December 31, 2012. We do not believe that the loss of any of our major purchasers would result in a material adverse effect on our ability to market future oil

and natural gas production. From time to time, we may enter into transactions that hedge the price of oil and natural gas. See “Item 7A. Quantitative and

Qualitative Disclosures About Market Risk – Commodity Price Risk.”

Competition and Markets

Competition in the Gulf Coast Basin, the deep water and deep shelf GOM, the Gulf Coast onshore, the Appalachia region and other onshore oil plays is

intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other

independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many

of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our

ability to compete. See “Item 1A. Risk Factors – Competition within our industry may adversely affect our operations.”

The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control, including but not

limited to the amount of domestic production and imports of foreign oil and liquefied natural gas, the marketing of competitive fuels, the proximity and

capacity of oil and natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and

state regulation of allowable rates of production, taxation and the conduct of drilling operations and federal regulation of oil and natural gas. In addition, the

restructuring of the natural gas pipeline industry eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. Producers of

natural gas have therefore been required to develop new markets among gas marketing companies, end users of natural gas and local distribution companies.

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

and maintaining bonding requirements in order to drill or operate wells, and 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 federal oil and gas leases, which are administered by the Bureau of Land Management (“BLM”) and the

Bureau of Ocean Energy Management (“BOEM”), a successor agency to the Minerals Management Service. 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 (“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 (“OCS”) of the GOM, calculation of royalty payments and the

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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 (“BSEE”), a new 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 (“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 (“FERC”), in contravention of rules prescribed by the FERC. In 2006, the FERC issued rules

implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the

purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or

artifice to defraud, to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading or

to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for

violations of the NGA up to $1 million per day per violation. The new 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 (“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. In recent years, 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 (“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 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 natural gas liquids is affected by the cost of transporting those products to

market. Interstate transportation rates for oil, natural gas liquids and other products are regulated by the FERC. The FERC has established an indexing system

for such transportation, which allows such pipelines to take an annual inflation-based rate increase.

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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 natural gas liquids 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 natural gas liquids pipelines will

affect us in a way that materially differs from the way it affects other crude oil, condensate and natural gas liquids 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 FERC 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 FERC or any other 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 the acquisition of 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.

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 hydrocarbons or wastes

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 (“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. We cannot predict at this time whether the

OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if there were

to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and damages could be material to our results

of operations and financial position.

Climate Change. In December 2009, the EPA 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 are, according to the EPA, contributing to warming of the Earth’s

atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse

gases under existing provisions of the Clean Air Act

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(“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, effective as of

January 2, 2011. 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, beginning in 2011 for emissions occurring in 2010, as well as certain onshore oil and natural gas production facilities,

on an annual basis, beginning in 2012 for emissions occurring in 2011. 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 onehalf 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 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. 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. 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. The EPA has also commenced a study of the potential environmental impacts of hydraulic fracturing activities on water resources. The EPA’s study

includes 18 separate research projects addressing topics such as water acquisitions, chemical mining, well injections, flowback and produced water,

wastewater treatment and waste disposal. The EPA has indicated that it expects to issue its study report in late 2014. In addition, 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. 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. In addition, 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. 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.

Air emissions. In August 2012, the EPA adopted new 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 natural gas liquids that come to the surface

during completion of the fracturing process. The requirement for flaring of gas not sent to a gathering line became effective on October 15, 2012, and all

operators are required to use “green completions” drilling equipment beginning January 1, 2015. The rules also establish specific requirements regarding

emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for

natural gas processing plants. 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.

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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 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 21, 2013, we had 386 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 web-site (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 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 web-site 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. We will make timely

disclosure by a Current Report on Form 8-K and on our web-site of any change to, or waiver from, the Code of Business Conduct and Ethics for our

principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available free of charge by writing us at: Chief

Financial Officer, Stone Energy Corporation, P.O. Box 52807, Lafayette, LA 70505. The annual CEO certification required by Section 303A.12 of the New

York Stock Exchange Listed Company Manual was submitted on June 5, 2012.

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

(“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 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 gas production;

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

• our outlook on oil and gas prices;

• estimates of our oil and 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;

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

• 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;

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

• 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:

New regulatory requirements and permitting procedures imposed by the BOEM could significantly delay our ability to obtain permits to drill

new wells in offshore waters.

Subsequent to the Deepwater Horizon incident in the GOM in April 2010, the BOEM issued a series of “Notice to Lessees” (“NTLs”) imposing new

regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These new 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.

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• 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.

• 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 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 much longer to review and approve permits for new wells than was

common prior to the Deepwater Horizon incident. The new rules also increase the cost of preparing each permit application and will increase the cost of each

new well, particularly for wells drilled in deeper waters on 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.

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 flow 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 our 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. If commodity prices decline in the

future, the decline could have adverse effects on our reserves and borrowing base.

The prices we receive for our oil and natural gas depend upon 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 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.

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 18% of our estimated proved reserves at December 31, 2012 (by volume) and 56% of our production during 2012

were associated with our Gulf Coast Basin 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 natural gas and oil 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.

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Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, 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

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 producing reserves contained in this Form 10-K represents the market

value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2012 on

average 12-month 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, 2012, approximately 44% 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 assumption 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 flow

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

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 assure you that additional debt or equity financing will be available or cash flows provided by operations will be sufficient to meet

these requirements.

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 production

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 costs. As a result, we may make

significant increases or decreases to our estimated asset retirement obligations in future periods. For example,

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because we operate in the GOM, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost 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 estimate 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.

The credit crisis and related turmoil in the global financial systems had an impact on our business and our financial condition. 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 flow

from operating activities and borrowings under our bank credit facility to fund our capital expenditures and have relied on the capital markets and asset

monetization transactions to provide us with additional capital for large or exceptional transactions. In the future, we may not be able to access adequate

funding under our bank credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination, or (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 bank group

after its evaluation of our proved oil and gas reserve values. Our borrowing base is scheduled to be redetermined by May 2013. Upon a redetermination, if

borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to repay a portion of our bank debt.

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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 flow 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 can be successfully completed.

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

Approximately 18% of our estimated proved reserves at December 31, 2012 (by volume) and 56% of our production during 2012 were associated with

our Gulf Coast Basin conventional shelf properties. Approximately 38% of our estimated proved reserves at December 31, 2012 (by volume) and 27% of our

production during 2012 were associated with our GOM deep water and deep shelf gas 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 natural gas prices remain 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. See “Item 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, however, what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.

Our actual production could differ materially from our forecasts.

From time to time, we provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates,

including expectations of production from existing wells. In addition, our forecasts 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.

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Lower oil and 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 cost 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 flow from operating activities, but does reduce net income. We also assess the carrying amount of goodwill when events occur

that may indicate an impairment exists. These events include, for example, a significant decline in oil and gas prices or a decline in our market capitalization.

The risk that we will be required to write-down the carrying value of oil and gas properties and goodwill 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. 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 and wells in the Rocky Mountain region and other regions. These activities are more uncertain than drilling

in areas that are developed and have established production. Our operations in these regions are still in the early stages. 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 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. 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 new 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 net revenue after operating and other

costs to recoup drilling costs.

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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 natural gas and oil 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. Our deep water drilling and operations require the application of recently developed technologies that involve a

higher risk of mechanical failure. 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 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 and hurricane related events. We currently have insurance policies that include coverage for general

liability, physical damage to our oil and gas properties, operational control of wells, oil pollution, 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 and damages and losses.

Currently, we have general liability insurance coverage with an annual aggregate limit of up to $375 million on a 100% working interest basis. We

currently purchase an offshore property physical damage policy that contains an $80 million annual aggregate named windstorm limit. 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 $600 million per occurrence. Additionally, we maintain $150 million in oil pollution liability coverage.

Our general liability, control of well and oil pollution liability policy limits are scaled proportionately to our working interests, and 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, which might severely impact our financial position.

We may be liable for damages from an event relating to a project in which we are a non-operator, but have a working interest in such project. Such an event

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 each May. Future insurance coverage for our industry could increase in cost

and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we

believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and

we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new

governmental regulations. This may cause us to restrict our operations in the GOM, which might severely impact our financial position. The occurrence of a

significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

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

The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have

subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse affect 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 United States federal, state and local governmental regulations that materially affect our

operations.

Our oil and gas operations are subject to various United States federal, state and local laws and regulations. These laws and regulations may be changed

in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our

drilling activities in environmentally sensitive areas, such as wetlands, and restrictions on the way we can release materials into the environment; bonds or

other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment 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

gas, these agencies have restricted the rates of flow of oil and 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 the federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and

Resource Conservation and Recovery Act (“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 gas, by-products from oil and 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 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. These arrangements may include futures contracts on the New York Mercantile

Exchange (“NYMEX”) or the Intercontinental Exchange (“ICE”). While intended to reduce the effects of volatile oil and gas prices, such transactions,

depending on the hedging instrument used, may limit our potential gains if oil and 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.

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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 our lenders are secured by the security documents executed by the parties under our bank credit facility. Future

collateral requirements for our commodity hedging activities are uncertain and will depend on the arrangements we negotiate with the counterparty and the

volatility of oil and natural gas prices and market conditions.

Our Certificate of Incorporation and Bylaws have provisions that 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 board of directors is elected by plurality voting. Also, 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 the board of directors may

determine. Additional provisions 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 gas exploration and development may be eliminated as a

result of future legislation.

Legislation may be proposed that would, if enacted into law, 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 natural gas exploration and production companies. These changes include, but are

not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and

development costs; (iii) the elimination of the deduction for certain 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.

In December 2009, the EPA 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 are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic

changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing

provisions of the CAA. The EPA adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in

emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources,

effective as of January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a

number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state

environmental agencies to implement, the rules. 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, beginning in 2011 for emissions occurring in 2010, as well as certain onshore oil

and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

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In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost onehalf 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. If any such effects 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.

On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the

“Act”), was enacted that establishes 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, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking

under the Act the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps

that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by

the United States District Court for the District of Colombia in September of 2012 although the CFTC has stated that it will appeal the District Court’s

decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer”

and “major swap participant.” The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and

trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition new regulations may require us to comply with

margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be

finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result it is not possible at this time to predict

with certainty the full effects of the Act and CFTC rules on us and the timing of such effects. The Act also may require the counterparties to our derivative

instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting

requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative

contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative

contracts, and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations,

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 natural 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 regulations is to lower commodity prices. Any of these consequences could have material adverse effect on our financial condition and our results of

operations.

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 from tight formations. We routinely

utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals

under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas

commissions. However, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the

SDWA’s Underground Injection Control Program. The White House Council on Environmental Quality is coordinating an administration-wide review of

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hydraulic fracturing practices, and a number of federal agencies are analyzing a number of environmental issues associated with hydraulic fracturing. The

EPA has commenced a comprehensive study of the potential environmental effects of hydraulic fracturing activities on water resources. The EPA’s study

includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, wastewater

treatment and waste disposal. The EPA has indicated that it expects to issue its study report in late 2014. In addition, the U.S. Department of Energy and the

U.S. Government Accountability Office are studying various aspects of hydraulic fracturing, and the U.S. Department of the Interior is considering adopting

new permitting and disclosure requirements for hydraulic fracturing activities performed on federal lands. These studies, depending on their results, could

spur initiatives to regulate hydraulic fracturing under the SDWA or other federal programs. In addition, 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, including states in which we operate. For example, effective February 1, 2012, the Railroad Commission of Texas (the entity that regulates oil and

natural gas production in Texas) began requiring all operators to disclose on a public website the chemical ingredients and water volumes used to hydraulically

fracture wells in Texas. The disclosure of proprietary information regarding chemicals or formulas used in hydraulic fracturing could diminish the value of

such information and could result in competitive harm to us. 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

As of February 21, 2013, our property portfolio consisted of 65 active properties and 129 primary term leases in the Gulf Coast Basin (onshore and

offshore), five active properties in the Appalachia region, three active properties in the Rocky Mountain region and one active property in the Eagle Ford Shale

formation. We serve as operator on 71% of our active properties. The properties that we operate accounted for 92% of our year-end 2012 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 the 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 twenty 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, 2012 were prepared by Netherland, Sewell & Associates, Inc. (“NSA”), a nationally recognized

engineering firm. NSA provides a complete range of geological, geophysical, petrophysical and engineering services and has the technical experience and

ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. NSA has a technical staff of over 70

professionals who are intimately familiar with recognized industry reserve and resource definitions, specifically those set forth by the SEC. NSA’s letter is

filed as an exhibit to this Form 10-K.

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The following table sets forth our estimated proved oil and gas reserves (approximately 44% of which are located in the Appalachian region, 34% are

located in the GOM deep water and 22% are located in the conventional shelf/deep gas) as of December 31, 2012. The 2012 average 12-month oil and gas

prices net of differentials were $101.20 per Bbl of oil, $38.23 per Bbl of natural gas liquids (“NGLs”) and $2.68 per Mcf of gas.

Summary of Oil, Natural Gas and NGL Reserves as of December 31, 2012

 

Oil

(MBbls) 

Natural 

Gas

Liquids

(MBbls) 

Natural Gas

(MMcf) 

Oil, Natural

Gas and

NGL’s

(MMcfe)

Reserves Category: 

PROVED 

Developed 29,005 8,592 210,956 436,540 

Undeveloped 15,913 9,474 184,418 336,745 

TOTAL PROVED 44,918 18,066 395,374 773,285 

At December 31, 2012, we reported estimated proved undeveloped reserves (“PUDs”) of 336.7 Bcfe, which accounted for 44% of our total estimated

proved oil and gas reserves. This figure ties to a projected 88 new wells (311.8 Bcfe) and ten sidetrack wells from existing wellbores (24.9 Bcfe). Our timetable

for the ten 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 88 PUD locations, we project 25 wells to be drilled in 2013 (122.2 Bcfe); ten

wells in 2014 (42.2 Bcfe); 29 wells in 2015 (76.9 Bcfe); fourteen wells in 2016 (41.3 Bcfe), and ten wells in 2017 (29.2 Bcfe). None of these 88 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 2012.

 

Oil, Natural

Gas and

NGLs

(MMcfe)

Future

Development

Costs

($ in thousands)

PUDs beginning of year

 241,656 $ 607,995 

Revisions of previous estimates (47,153) (176,995) 

Conversions to proved developed reserves (47,505) (33,835) 

Additional PUDs added 189,747 268,071 

PUDs end of year 336,745 $ 665,236 

During 2012 we invested approximately $33.8 million to convert 47.5 Bcfe of proved undeveloped reserves to proved developed reserves, mainly in the

Appalachian region.

The following represents additional information on our significant properties:

Field Name Location 

2012

Production

(MMcfe) 

December 31,

2012

Estimated

Proved Reserves

(MMcfe) 

Nature of

Interest

Mary Appalachia 11,544 281,843 Working 

Pompano GOM Deep Water 10,310 175,642 Working 

Mississippi Canyon Block 109 GOM Deep Water 9,765 75,291 Working 

Bayou Hebert GOM Deep Gas 3,254 33,317 Working 

Heather Appalachia 2,799 33,008 Working 

Ship Shoal Block 113 GOM Shelf 11,745 25,657 Working 

Ewing Bank Block 305 GOM Shelf 3,309 19,942 Working 

Main Pass Block 288 GOM Shelf 2,756 13,080 Working 

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

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and production activities may justify revisions of estimates that were made previously. If significant, these revisions would change the schedule of any further

production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately

recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including

geological success, prices, future production levels, operating costs, development costs and income taxes that may not prove to be correct. Predictions about

prices and future production levels are subject to great uncertainty, and the meaningfulness of these estimates depends on the accuracy of the assumptions

upon which they are based.

As an operator of domestic oil and gas properties, we have filed U.S. Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,”

as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The differences are

attributable to the fact that Form EIA-23 requires that an operator report the total reserves attributable to wells that it operates, without regard to percentage

ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis) or non-operated wells in which it owns an interest.

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 during the periods indicated.

 Year Ended December 31,

 2012 2011 2010

 (In thousands)

Acquisition costs, net of sales of unevaluated properties $ 102,807 $ 270,354 $127,069 

Development costs (1) 395,555 426,355 241,387 

Exploratory costs 81,458 84,199 42,205 

Subtotal 579,820 780,908 410,661 

Capitalized salaries, general and administrative costs and interest, net of fees and

reimbursements 62,664 66,111 51,016 

Total additions to oil and gas properties, net $ 642,484 $ 847,019 $461,677 

(1) Includes capitalized asset retirement costs of $95,293, $96,386 and $56,444 for the years ended December 31, 2012, 2011 and 2010, 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,

 2012 2011 2010

Production: 

Oil (MBbls) 7,135 6,427 5,714 

Natural gas (MMcf) 42,569 38,466 41,168 

Natural gas liquids (MBbls) 1,163 506 574 

Oil, natural gas and NGLs (MMcfe) 92,357 80,064 78,896 

Average sales prices: (1) 

Oil (per Bbl) $ 106.70 $ 103.31 $ 73.14 

Natural gas (per Mcf) 3.17 4.44 5.12 

Natural gas liquids (per Bbl) 41.70 59.28 47.86 

Oil, natural gas and NGLs (per Mcfe) 10.23 10.80 8.32 

Expenses (per Mcfe): 

Lease operating expenses (2) $ 2.33 $ 2.20 $ 1.90 

(1) Includes the settlement of effective hedging contracts.

(2) 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, 2012. We completed the acquisition of our interest in the Pompano field on December 28, 2011.

FIELD: Mary Year Ended December 31,

 2012 2011 2010

Production: 

Oil (MBbls) 340 25 — 

Natural gas (MMcf) 6,815 977 79 

Natural gas liquids (MBbls) 448 — — 

Oil, natural gas and NGLs (MMcfe) 11,544 1,125 79 

Average sales prices: 

Oil (per Bbl) $ 54.19 $75.60 $ — 

Natural gas (per Mcf) 3.27 6.08 4.78 

Natural gas liquids (per Bbl) 33.94 — — 

Oil, natural gas and NGLs (per Mcfe) 4.84 6.94 4.78 

Expenses (per Mcfe): 

Lease operating expenses (1) $ 1.14 $ 1.40 $1.51 

FIELD: Pompano Year Ended December 31,

 2012 2011 (a) 2010

Production: 

Oil (MBbls) 1,266 — — 

Natural gas (MMcf) 1,980 — — 

Natural gas liquids (MBbls) 122 — — 

Oil, natural gas and NGLs (MMcfe) 10,310 — — 

Average sales prices: 

Oil (per Bbl) $108.65 $ — $— 

Natural gas (per Mcf) 2.02 — — 

Natural gas liquids (per Bbl) 45.70 — — 

Oil, natural gas and NGLs (per Mcfe) 14.28 — — 

Expenses (per Mcfe): 

Lease operating expenses (1) $ 2.01 $ — $— 

(a) Amounts for 2011 are immaterial. We completed the acquisition of the Pompano field on December 28, 2011.

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

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

 Year Ended December 31,

 2012 2011 2010

 Gross Net Gross Net Gross Net

Exploratory Wells: 

Productive 1.00 0.43 6.00 3.00 6.00 4.10 

Dry — — 1.00 0.64 — — 

Development Wells: 

Productive 33.00 23.16 37.00 32.92 20.00 15.75 

Dry 3.00 3.00 — — — — 

During the period beginning January 1, 2013 and ending February 21, 2013, we participated in the drilling of 4.00 gross (3.05 net) development wells.

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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, 2012.

 Gross Net

Productive Wells: 

Oil (1): 

Gulf Coast Basin 175 129 

Onshore Oil 10 4 

Appalachia — — 

 185 133 

Gas (2): 

Gulf Coast Basin 71 43 

Onshore Oil — — 

Appalachia 6 5 44 

 136 87 

Total 321 220 

Developed Acres: 

Gulf Coast Basin 307,868 279,881 

Onshore Oil 30,361 30,361 

Appalachia 27,101 26,247 

 365,330 336,489 

Undeveloped Acres (3): 

Gulf Coast Basin 539,878 535,193 

Onshore Oil 65,771 62,174 

Appalachia 75,794 66,992 

 681,443 664,359 

Total 1,046,773 1,000,848 

(1) 15 gross wells each have dual completions.

(2) 8 gross wells each have dual completions.

(3) Leases covering approximately 14% of our undeveloped gross acreage will expire in 2013, 15% in 2014, 4% in 2015, 10% in 2016, 6% in 2017, 14%

in 2018, 9% in 2019, 2% in 2020 and 26% thereafter.

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

On December 30, 2004, we were served with two petitions (civil action numbers 2004-6227 and 2004-6228) filed by the Louisiana Department of

Revenue (“LDR”) in the 15 Judicial District Court (Parish of Lafayette, Louisiana) claiming additional franchise taxes due. In one case, the LDR is seeking

additional franchise taxes from Stone in the amount of $640,000, plus accrued interest of $352,000 (calculated through December 15, 2004), for the franchise

tax year 2001. In the other case, the LDR is seeking additional franchise taxes from Stone (as successor to Basin Exploration, Inc.) in the amount of $274,000,

plus accrued interest of $159,000 (calculated through December 15, 2004), for the franchise tax years 1999, 2000 and 2001. On December 29, 2005, the

LDR filed another petition (civil action number 2005-6524) in the 15 Judicial District Court claiming additional franchise taxes due for the franchise tax

years 2002 and 2003 in the amount of $2.6 million, plus accrued interest of $1.2 million (calculated through December 15, 2005). Also, on January 2, 2008,

we were served with a petition (civil action number 2007-6754) claiming $1.5 million of additional franchise taxes due for the 2004 franchise tax year, plus

accrued interest of $800,000 (calculated through November 30, 2007). Further, on January 7, 2009, we were served with a petition (civil action number 2008-

7193) claiming

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additional franchise taxes due for the franchise tax years 2005 and 2006 in the amount of $4.0 million, plus accrued interest of $1.7 million (calculated

through October 21, 2008). In addition, we have received proposed assessments from the LDR for additional franchise taxes in the amount of $8.1 million

resulting from audits of Stone and our subsidiaries. These assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties

located on the OCS, which are transported through the State of Louisiana, should be sourced to the State of Louisiana for purposes of computing the

Louisiana franchise tax apportionment ratio. We disagree with these contentions and intend to vigorously defend ourselves against these claims. The franchise

tax years 2010, 2011 and 2012 for Stone remain subject to examination.

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. The notice indicates that BSEE may seek to impose a penalty of up to $25,000 a day for up

to as many as eight days of alleged improper venting of gas at the platform. We believe that the conditions observed were not actually violations of applicable

rules and have initiated discussions with BSEE to resolve the matter. We do not believe that this proceeding will have a material adverse effect on our financial

condition or results of operations.

Litigation is 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 these matters and are unable to estimate a range of possible losses or any minimum loss

from such matters.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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

2011 

First Quarter $ 33.49 $ 21.28 

Second Quarter 35.94 27.44 

Third Quarter 34.46 16.19 

Fourth Quarter 29.71 14.64 

2012 

First Quarter $ 35.47 $25.61 

Second Quarter 29.83 20.80 

Third Quarter 27.87 22.07 

Fourth Quarter 25.71 19.27 

2013 

First Quarter (through February 21, 2013) $ 23.40 $19.62 

On February 21, 2013, the last reported sales price on the New York Stock Exchange Composite Tape was $20.62 per share. As of that date, there were

457 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 / % Senior Convertible Notes due 2017 (the “2017 Convertible Notes”), our 8 / % Senior Notes due 2017 (the “2017 Notes”) and our

7 / % 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 to pay taxes associated

with the employees’ vesting of restricted stock. The following table sets forth information regarding our repurchases or acquisitions of common stock during

the fourth quarter of 2012:

Period 

Total Number

of Shares (or

Units)

Purchased 

Average

Price Paid

per Share (or

Unit) 

Total Number of

Shares (or Units)

Purchased as Part

of Publicly

Announced Plans

or Programs 

Maximum Number (or

Approximate Dollar

Value) of Shares (or Units)

that May Yet Be

Purchased Under the

Plans or Programs

Share Repurchase Program: 

October 2012 — — — 

November 2012 — — — 

December 2012 — — — 

 — — — $ 92,928,632 

Other: 

October 2012 — — — 

November 2012 — — — 

December 2012 — — — 

 — — — N/A 

Total Fourth Quarter 2012 — $ — — 

There were no repurchases of common stock under our share repurchase program and no shares withheld from employees to pay taxes associated with

any vesting of restricted stock during the fourth quarter of 2012.

Equity Compensation Plan Information

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

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Stock Performance Graph

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

1. $100 was invested in the company’s common stock, the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Peer Group (as

defined below) on December 31, 2007 at $46.91 per share for the company’s common stock and at the closing price of the stocks

comprising the S&P 500 Index and the Peer Group, respectively, on such date.

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

beginning of the period.

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

Measurement Period

(Fiscal Year Covered)

 SGY 

2012 Peer

Group 

2011 Peer

Group 

S&P 500

Index

12/31/08 23.49 50.58 53.80 63.00 

12/31/09 38.48 80.77 87.30 79.67 

12/31/10 47.52 102.46 105.30 91.68 

12/31/11 56.24 94.89 95.89 93.61 

12/31/12 43.74 93.66 92.18 108.59 

The companies that comprised our Peer Group in 2012 were: ATP Oil & Gas Corporation, Cabot Oil & Gas Corporation, Callon Petroleum Company,

Carrizo Oil & Gas, Inc., Cimarex Energy Company, Comstock Resources, Inc., Denbury Resources Inc., Energy Partners, Ltd., Energy XXI (Bermuda)

Limited, Exco Resources Inc., McMoRan Exploration Company, Newfield Exploration Company, Petroleum Development Corporation, PetroQuest Energy,

Inc., Plains Exploration & Production Company, Range Resources Corporation, SM Energy Company, Swift Energy Company, W&T Offshore, Inc. and

Whiting Petroleum Corporation. Plains Exploration & Production Company replaced Petrohawk Energy Corporation after Petrohawk Energy Corporation was

acquired by BHP Billiton in August 2011.

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,

2012. This information is derived from our Consolidated Financial Statements and the notes thereto. See “Item 7. Management’s Discussion and Analysis

of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.” The information included in this

table for the years ended December 31, 2009 and 2008 includes the effects of corrections on the previously reported financial statements.

 Year Ended December 31,

 2012 2011 2010 2009 2008

 (In thousands, except per share amounts)

Statement of Operations Data: 

Operating revenue: 

Oil production $ 761,304 $ 663,958 $ 417,948 $ 438,942 $ 461,050 

Gas production 134,739 170,611 210,686 272,353 336,665 

Natural gas liquids production 48,498 29,996 27,473 — — 

Other operational income 3,520 3,938 5,916 4,326 5,989 

Derivative income, net 3,428 1,418 3,265 3,061 3,327 

Total operating revenue 951,489 869,921 665,288 718,682 807,031 

Operating expenses: 

Lease operating expenses 215,003 175,881 150,212 156,786 171,107 

Transportation, processing and gathering expenses 21,782 8,958 7,218 — — 

Other operational expenses 267 2,149 5,579 11,798 — 

Production taxes 10,015 9,380 5,808 7,920 7,990 

Depreciation, depletion and amortization 344,365 280,020 248,201 259,639 288,384 

Write-down of oil and gas properties — — — 508,989 1,324,327 

Goodwill impairment — — — — 465,985 

Accretion expense 33,331 30,764 34,469 39,306 17,392 

Salaries, general and administrative expenses 54,648 40,169 42,759 41,367 43,504 

Incentive compensation expense 8,113 11,600 5,888 6,402 2,315 

Total operating expenses 687,524 558,921 500,134 1,032,207 2,321,004 

Income (loss) from operations 263,965 311,000 165,154 (313,525) (1,513,973) 

Other (income) expenses: 

Interest expense 30,375 9,289 12,192 21,361 13,243 

Interest income (600) (420) (1,464) (528) (11,250) 

Other income (1,805) (1,942) (776) (36) 189 

Loss on early extinguishment of debt 1,972 607 1,820 — — 

Other expense — — 671 508 — 

Total other expenses 29,942 7,534 12,443 21,305 2,182 

Net income (loss) before income taxes 234,023 303,466 152,711 (334,830) (1,516,155) 

Income tax provision (benefit) 84,597 109,134 56,282 (116,559) (369,146) 

Net income (loss) 149,426 194,332 96,429 (218,271) (1,147,009) 

Net income (loss) attributable to non-controlling interest — — — 27 (77) 

Net income (loss) attributable to Stone Energy Corp. $ 149,426 $ 194,332 $ 96,429 ($ 218,298) ($ 1,146,932) 

Earnings and dividends per common share: 

Basic earnings (loss) per share $ 3.03 $ 3.97 $ 1.99 ($ 4.97) ($ 35.89) 

Diluted earnings (loss) per share $ 3.03 $ 3.97 $ 1.99 ($ 4.97) ($ 35.89) 

Cash dividends declared per share — — — — — 

Cash Flow Data: 

Net cash provided by operating activities $ 509,749 $ 570,850 $ 424,794 $ 507,787 $ 522,478 

Net cash used in investing activities (568,688) (679,250) (374,088) (316,079) (1,357,907) 

Net cash provided by (used in) financing activities 300,014 39,895 (13,043) (190,552) 428,440 

Balance Sheet Data (at end of period): 

Working capital (deficit) $ 300,348 ($ 13,282) $ 30,382 $ 26,137 $ 123,339 

Oil and gas properties, net 2,182,095 1,875,048 1,397,809 1,185,709 1,628,170 

Total assets 2,776,431 2,165,751 1,679,090 1,454,242 2,109,852 

Long-term debt, less current potion 914,126 620,000 575,000 575,000 825,000 

Stone Energy Corporation stockholders’ equity 872,133 667,829 430,357 325,659 577,391 

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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, 2012. Our Consolidated Financial Statements and the notes thereto, which are found elsewhere in this Form 10-K, contain detailed

information that should be referred to in conjunction with the following discussion. See “Item 1A. Risk Factors” and “Item 8. Financial Statements and

Supplementary Data – Note 1.” Certain 2011 and 2010 amounts have been changed from amounts previously presented to conform to the current

presentation.

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 Gulf Coast Basin since our incorporation in 1993 and have established a technical and operational expertise in this

area. We have expanded our reserve base outside of the conventional shelf of the GOM and into the more prolific reserve basins of the GOM deep water and

Gulf Coast deep gas as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia. See “Item 1. Business – Strategy and

Operational Overview.”

2012 Significant Events.

Diversification Strategy – In 2012, we had continued progress in our diversification strategy, resulting in a reserve mix of 44% Appalachia, 34% Deep

Water, and 22% Conventional Shelf/Deep Gas on a volume equivalent basis. Additionally, our programs in Appalachia, deep water and deep gas all generated

increased reserve volumes in 2012, resulting in company-wide reserve growth of over 20% from 2011. Our average reserve life has grown from 5.2 years in

2009 to approximately 8.5 years currently.

Issuance of 2017 Convertible Notes – On March 6, 2012, we issued in a private offering $300 million in aggregate principal amount of 1 / % Senior

Convertible Notes due 2017. The net proceeds from the offering after deducting fees and expenses totaled $291.1 million. The 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 $1,000 principal amount of 2017 Convertible Notes, which corresponds to an initial conversion price of approximately $42.65 per

share of our common stock. In connection with the offering, we entered into convertible note hedge transactions in respect of our common stock and entered

into separate warrant transactions at a higher strike price of $55.91, subject to certain adjustments. The net proceeds from the offering and the proceeds from

the warrant transactions were used to fund the cost of the convertible note hedge transactions, to repay outstanding borrowings under our bank credit facility

and to fund capital expenditures. The remaining proceeds will be used for general corporate purposes.

Issuance of 2022 Senior Notes – On November 8, 2012, we completed a public offering of $300 million aggregate principal amount of 7 / % Senior

Notes due 2022. The net proceeds from the offering after deducting fees and expenses totaled $293.2 million. Approximately $204.4 million of the net proceeds

from the offering were used to fund the tender offer and consent solicitation and redemption of our outstanding 6 / % Senior Subordinated Notes due 2014 (the

“2014 Notes”). The remaining proceeds will be used for general corporate purposes. As of December 31, 2102, we had approximately $279.5 million of cash

on hand.

2013 Outlook.

Our 2013 capital expenditure budget is approximately $650 million. This figure compares with a $625 million capital budget for 2012 and excludes

material acquisitions and capitalized salaries, general and administrative expenses and interest. The budget is spread across our major areas of investment

with approximately 29% allocated to the deep water, 8% allocated to deep gas projects, 27% allocated to the GOM conventional shelf, 33% allocated to the

Marcellus Shale and 3% allocated to onshore exploration projects. The allocation of capital across the various areas is subject to change based on several

factors including permitting times, rig availability, non-operator decisions, farm-in opportunities and commodity pricing.

Known Trends and Uncertainties.

Hurricanes – Since the majority of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production.

Additionally, affordable insurance coverage for property damage to our facilities for hurricanes has been difficult to obtain for some time. We have narrowed

our insurance coverage to selected properties, increased our deductibles and are assuming more hurricane related risk in the environment of rising insurance

rates. 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 acceleration of plugging and abandonment costs.

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Louisiana Franchise Taxes – We have been involved in litigation with the State of Louisiana over the proper computation of franchise taxes allocable to

the state. This litigation relates to the state’s position that sales of crude oil and natural gas from properties located on the OCS, which are transported through

the State of Louisiana, should be sourced to Louisiana for purposes of computing franchise taxes. We disagree with the state’s position. However, if the state’s

position were to be upheld, we could incur additional expense for alleged underpaid franchise taxes in prior years and higher franchise tax expense in future

years. See “Item 3. Legal Proceedings.”

Deep Water Operations – With our acquisition of interests in the Pompano field, we are now operating two significant properties in the deep water of

the GOM. 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.

Earnings Per Share – On March 6, 2012, we issued $300 million of 2017 Convertible Notes. These notes are convertible into cash, shares of our

common stock or a combination thereof at our election. Current accounting standards require us to use the treasury method for determining potential dilution in

our diluted earnings per share computation since it is management’s intention to settle the principal in cash. However, if due to changes in facts and

circumstances beyond our control such intention were to change, or it becomes probable that we will be unable to settle the principal in cash, we could be

required to change our methodology for determining diluted earnings per share to the if-converted method. The if-converted method would result in a

substantial dilutive effect on diluted earnings per share when compared to the treasury method.

Liquidity and Capital Resources

At February 21, 2013, we had $379.0 million of availability under our bank credit facility and cash on hand of approximately $315.0 million. Our

capital expenditure budget for 2013 has been set at $650 million, which excludes material acquisitions and capitalized salaries, general and administrative

expenses and interest. Based on our outlook of commodity prices and our estimated production, we expect our 2013 capital expenditures to exceed our cash

flow from operating activities. We intend to finance our capital expenditure budget with cash flow from operating activities and cash on hand.

Cash Flow and Working Capital. Net cash flow from operating activities totaled $509.7 million during the year ended December 31, 2012 compared

to $570.9 million and $424.8 million during the years ended December 31, 2011 and 2010, respectively.

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 used in investing activities totaled

$679.3 million during the year ended December 31, 2011, which primarily represents our investment in oil and natural gas properties of $764.9 million

offset by proceeds from the sale of oil and natural gas properties of $87.9 million. Approximately $270.4 million of the investment in oil and gas properties in

2011 related to leasehold acquisitions and the acquisition of producing properties. Net cash used in investing activities totaled $374.1 million during the year

ended December 31, 2010, which primarily represents our investment in oil and natural gas properties of $401.8 million offset by proceeds from the sale of oil

and natural gas properties of $31.6 million.

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 our 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 (see Notes to Consolidated Financial Statements – NOTE 11 – Long-Term Debt). Additionally, we received $293.2 million of

net proceeds from the issuance of our 2022 Notes. During 2012, we used $200.7 million for the redemption of our 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. Net cash provided by

financing activities totaled $39.9 million for the year ended December 31, 2011, which primarily represents borrowings net of repayments under our bank

credit facility of $45.0 million, less $4.0 million of deferred financing costs associated with our new bank credit facility and $2.6 million of net payments for

share based compensation. Net cash used in financing activities totaled $13.0 million for the year ended December 31, 2010, which primarily represents

repayments of borrowings under our bank credit facility of $175 million, the redemption of our 8 / % Senior Subordinated Notes due 2011 (the “2011

Notes”) of $200.5 million, net of proceeds from the public offering of our 2017 Notes of approximately $375 million less $11.5 million of deferred financing

costs.

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We had working capital at December 31, 2012 of $300.3 million. Included in working capital at December 31, 2012 is a portion of the proceeds received

from the issuance of the 2017 Convertible Notes and the 2022 Notes.

Capital Expenditures. During the year ended December 31, 2012, additions to oil and gas property costs of $642.5 million included $102.8 million of

lease and property acquisition costs, $25.0 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and

$37.7 million of capitalized interest. These investments were financed with cash flow from operating activities and the net proceeds from the 2017 Convertible

Notes.

Bank Credit Facility. On April 26, 2011, we entered into an amended and restated revolving credit facility totaling $700 million (subject to borrowing

base limitations) through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. On October 22,

2012, our borrowing base under our bank credit facility was reaffirmed at $400 million. As of December 31, 2012 and February 21, 2013, we had no

outstanding borrowings under our bank credit facility and letters of credit totaling $21.0 million had been issued pursuant to the bank credit facility, leaving

$379.0 million of availability under the facility. Our bank credit facility is guaranteed by our only subsidiary, Stone Energy Offshore, L.L.C. (“Stone

Offshore”).

The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders taking into consideration the

estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries 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 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 gas reserves representing at least 80% of the discounted present value of the future net

cash flows from their oil and gas reserves reviewed in determining the borrowing base. At our option, loans under the bank credit facility will bear interest at a

rate based on the adjusted London Interbank Offering Rate plus an applicable margin, or a rate based on the prime rate or Federal funds rate plus an applicable

margin.

Under the financial covenants of our bank credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the

credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) 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 3.0 to 1. As of December 31, 2012, our debt to

EBITDA Ratio was 1.55 to 1 and our EBITDA to consolidated Net Interest Expense Ratio was approximately 21.56 to 1. In addition, the bank credit facility

includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of ownership 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.

7 / % Senior Notes due 2022. On November 8, 2012, we completed the public offering of $300 million aggregate principal amount of our 2022 Notes.

The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $293.2 million. Approximately $204.4

million of the net proceeds from the offering were used to fund the tender offer and consent solicitation and redemption of our outstanding 2014 Notes. The

remaining proceeds will be used for general corporate purposes.

6 / % Senior Subordinated Notes due 2014. In November 2012, we used proceeds from the 2022 Notes offering to purchase our 2014 Notes

pursuant to a tender offer and consent solicitation. In December 2012, the remaining 2014 Notes were redeemed in full. The total cost of the redemption was

$204.4 million, which included $200.7 million to redeem the notes plus accrued and unpaid interest of $3.7 million. The transaction resulted in a charge to

earnings of $2.0 million in 2012.

1 / % Senior Convertible Notes due 2017. On March 6, 2012, we issued in a private offering $300 million in aggregate principal amount of 2017

Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The net proceeds from the sale of the 2017 Convertible

Notes were $291.1 million, after deducting fees and expenses. The 2017 Convertible Notes mature on March 1, 2017, unless earlier converted or repurchased.

We may not redeem the 2017 Convertible Notes at our option prior to the maturity date.

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 $1,000 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, 2012, our closing share price was

$20.52. 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. Upon

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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. Prior to December 1, 2016, the 2017 Convertible Notes will be convertible only upon the occurrence of certain events and during certain

periods, and thereafter, at any time until the second scheduled trading day immediately preceding the maturity date.

In connection with the offering, we entered into convertible note hedge transactions in respect of our common stock. These convertible note hedge

transactions are expected to reduce the potential dilution upon future conversion of the 2017 Convertible Notes. In addition, we entered into separate warrant

transactions at a higher strike price. The warrant transactions could separately have a dilutive effect to the extent that the market value per share of our

common stock exceeds the applicable strike price of the warrants.

We applied a portion of the net proceeds of $291.1 million from the sale of the 2017 Convertible Notes and the proceeds from the warrant transactions

of $40.1 million to fund the cost of the convertible note hedge transactions of $70.8 million. We also used a portion of the net proceeds to repay $70 million of

outstanding borrowings under our bank credit facility.

Share Repurchase Program. On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to

$100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is

subject to business and market conditions, and may be suspended or discontinued at any time. Through December 31, 2012, 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, 2012, 2011 or 2010.

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

Contractual Obligations and Other Commitments

The following table summarizes our significant contractual obligations and commitments, other than hedging contracts, by maturity as of December 31,

2012 (in thousands):

 Total 

Less

than

1 Year 1-3 Years 4-5 Years 

More

than

5 Years

Contractual Obligations and Commitments: 

1 / % Senior Convertible Notes due 2017 $ 300,000 $ — $ — $ 300,000 $ — 

8 / % Senior Notes due 2017 375,000 — — 375,000 — 

7 / % Senior Notes due 2022 300,000 — — — 300,000 

Interest and commitment fees (1) 383,975 62,015 121,546 87,914 112,500 

Asset retirement obligations including accretion 878,551 68,142 233,123 100,054 477,232 

Rig commitments 33,712 33,712 — — — 

Seismic data commitments (2) 18,587 11,087 7,500 — — 

Operating lease obligations 2,237 612 1,080 463 82 

Total Contractual Obligations and Commitments $2,292,062 $175,568 $ 363,249 $863,431 $889,814 

(1) Includes interest payable on the 2017 Notes, 2022 Notes and 2017 Convertible Notes. Assumes 0.5% fee on unused commitments under the bank credit

facility.

(2) Represents pre-commitments for seismic data purchases.

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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

2012 0.45 0.55 

2011 0.33 0.65 

2010 0.51 0.65 

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 offsite 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

2012 Compared to 2011. 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 gas reserves. See “Item 2. Properties – Oil and Natural Gas Reserves.”

 Year Ended December 31,

 2012 2011 Variance % Change

Production: 

Oil (MBbls) 7,135 6,427 708 11% 

Natural gas (MMcf) 42,569 38,466 4,103 11% 

Natural gas liquids (MBbls) 1,163 506 657 130% 

Oil, natural gas and NGLs (MMcfe) 92,357 80,064 12,293 15% 

Average prices: (1) 

Oil (per Bbl) $ 106.70 $ 103.31 $ 3.39 3% 

Natural gas (per Mcf) 3.17 4.44 (1.27) (29%) 

Natural gas liquids (per Bbl) 41.70 59.28 (17.58) (30%) 

Oil, natural gas and NGLs (per Mcfe) 10.23 10.80 (0.57) (5%) 

Expenses (per Mcfe): 

Lease operating expenses $ 2.33 $ 2.20 $ 0.13 6% 

Salaries, general and administrative expenses (2) 0.59 0.50 0.09 18% 

DD&A expense on oil and gas properties 3.69 3.45 0.24 7% 

Estimated Proved Reserves at December 31: 

Oil (MBbls) 44,918 45,655 (737) (2%) 

Natural gas (MMcf) 395,374 325,479 69,895 22% 

Natural gas liquids (MBbls) 18,066 4,405 13,661 310% 

Oil, natural gas and NGLs (MMcfe) 773,285 625,839 147,446 24% 

(1) Includes the settlement of effective hedging contracts.

(2) Exclusive of incentive compensation expense.

Net Income. For the year ended December 31, 2012, we reported net income totaling $149.4 million, or $3.03 per share, compared to net income for the

year ended December 31, 2011 of $194.3 million, or $3.97 per share. All per share amounts are on a diluted basis.

In the first quarter of 2012, we began reporting NGL volumes and revenues separately from gas volumes. Historically, we reported “wet” gas volumes,

which included entrained liquids. We now report NGLs and “dry” gas (shrunk for removal of liquids) volumes. Production volumes, revenues and prices for

the year ended December 31, 2011 have been reclassified to conform to the current presentation.

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

Production. During the year ended December 31, 2012, total production volumes increased to 92.4 Bcfe compared to 80.1 Bcfe produced during the

comparable 2011 period, representing a 15% increase. Oil production during the year ended December 31, 2012 totaled approximately 7,135,000 Bbls

compared to 6,427,000 Bbls produced during the year ended December 31, 2011; natural gas production totaled 42.6 Bcf during the year ended December 31,

2012 compared to 38.5 Bcf produced during the comparable period of 2011; and NGL production during the year ended December 31, 2012 totaled

approximately 1,163,000 Bbls compared to 506,000 Bbls produced during the comparable period of 2011. The increase in NGL production resulted from our

liquids rich Pompano and Appalachia gas streams coming on line. Production commenced from our deep water Pyrenees well at Garden Banks 293 during the

first quarter of 2012. Included in production for the year ended December 31, 2012 is production from our Pompano field, which was acquired in December

2011.

Prices. Prices realized during the year ended December 31, 2012 averaged $106.70 per Bbl of oil, $3.17 per Mcf of natural gas and $41.70 per Bbl of

NGLs, or 5% lower, on an Mcfe basis, than 2011 average realized prices of $103.31 per Bbl of oil, $4.44 per Mcf of natural gas and $59.28 per Bbl of

NGLs. All unit pricing amounts include the settlement of effective hedging contracts.

We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. 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. During the year ended December 31, 2011, effective hedging transactions increased our average realized natural gas price by $0.51 per

Mcf and decreased our average realized oil price by $5.09 per Bbl.

Revenue. Oil, natural gas and NGL revenue increased 9% to $944.5 million during the year ended December 31, 2012 from $864.6 million during the

year ended December 31, 2011. The increase was attributable to a 15% increase in production quantities on a gas equivalent basis, partially offset by a 5%

decrease in average realized prices.

Expenses. Lease operating expenses for the years ended December 31, 2012 and 2011 totaled $215.0 million and $175.9 million, respectively. The

increase in lease operating expenses in 2012 was primarily attributable to the impact of expenses at our Pompano field, which was acquired in December 2011,

as well as seasonal major maintenance projects.

Transportation, processing and gathering expenses during the years ended December 31, 2012 and 2011 totaled $21.8 million and $9.0 million,

respectively. The increase resulted from our liquids rich Pompano and Appalachia gas streams coming on line in early 2012.

For the year ended December 31, 2011, other operational expenses of $2.1 million included $0.7 million for the settlement of litigation associated with an

expensed operation in the first quarter of 2011, a $0.3 million loss on the sale of non-dedicated tubular inventory and $1.1 million of miscellaneous inventory

charges.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the year ended December 31, 2012 totaled $341.1 million, or

$3.69 per Mcfe, compared to DD&A expense of $276.5 million, or $3.45 per Mcfe, for the year ended December 31, 2011. The increase in DD&A expense

on a unit basis in 2012 was attributable to the unit cost of current year net reserve additions (including future development costs) exceeding the per unit

amortizable base as of the beginning of the year.

For the years ended December 31, 2012 and 2011, salaries, general and administrative (“SG&A”) expenses (exclusive of incentive compensation) totaled

$54.6 million and $40.2 million, respectively. The increase in SG&A expenses in 2012 was primarily the result of increased staffing and compensation

adjustments (including stock based compensation) and a management fee of $1.0 million for transition services related to our Pompano acquisition. In 2011,

there was a $3.9 million credit to SG&A expenses, including previously unaccrued insurance proceeds.

For the years ended December 31, 2012 and 2011, incentive compensation expense totaled $8.1 million and $11.6 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, 2012 totaled $30.4 million, net of $37.7 million of capitalized interest, compared to interest expense of

$9.3 million, net of $42.0 million of capitalized interest, during the year ended December 31, 2011. The increase in interest expense is primarily the result of

interest associated with the 2017 Convertible Notes issued on March 6, 2012.

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2011 Compared to 2010. 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 gas reserves. See “Item 2. Properties – Oil and Natural Gas Reserves.”

 Year Ended December 31,

 2011 2010 Variance % Change

Production: 

Oil (MBbls) 6,427 5,714 713 12% 

Natural gas (MMcf) 38,466 41,168 (2,702) (7%) 

Natural gas liquids (MBbls) 506 574 (68) (12%) 

Oil, natural gas and NGLs (MMcfe) 80,064 78,896 1,168 1% 

Average prices: (1) 

Oil (per Bbl) $ 103.31 $ 73.14 $ 30.17 41% 

Natural gas (per Mcf) 4.44 5.12 (0.68) (13%) 

Natural gas liquids (per Bbl) 59.28 47.86 11.42 24% 

Oil, natural gas and NGLs (per Mcfe) 10.80 8.32 2.48 30% 

Expenses (per Mcfe): 

Lease operating expenses $ 2.20 $ 1.90 $ 0.30 16% 

Salaries, general and administrative expenses (2) 0.50 0.54 (0.04) (7%) 

DD&A expense on oil and gas properties 3.45 3.08 0.37 12% 

Estimated Proved Reserves at December 31: 

Oil (MBbls) 45,655 33,203 12,452 38% 

Natural gas (MMcf) 325,479 274,705 50,774 18% 

Natural gas liquids (MBbls) 4,405 — 4,405 N/A 

Oil, natural gas and NGLs (MMcfe) 625,839 473,923 151,916 32% 

(1) Includes the settlement of effective hedging contracts.

(2) Exclusive of incentive compensation expense.

Net Income. For the year ended December 31, 2011, we reported net income totaling $194.3 million, or $3.97 per share, compared to net income for the

year ended December 31, 2010 of $96.4 million, or $1.99 per share. All per share amounts are on a diluted basis.

In the first quarter of 2012, we began reporting NGL volumes and revenues separately from gas volumes. Historically, we reported “wet” gas volumes,

which included entrained liquids. We now report NGLs and “dry” gas (shrunk for removal of liquids) volumes. Production volumes, revenues and prices for

the years ended December 31, 2011 and 2010 have been reclassified to conform to the current presentation.

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

Production. During the year ended December 31, 2011, total production volumes increased to 80.1 Bcfe compared to 78.9 Bcfe produced during the

comparable 2010 period. Oil production during the year ended December 31, 2011 totaled approximately 6,427,000 Bbls compared to 5,714,000 Bbls

produced during the year ended December 31, 2010; natural gas production totaled 38.5 Bcf during the year ended December 31, 2011 compared to 41.2 Bcf

produced during the comparable period of 2010; and NGL production during the year ended December 31, 2011 totaled approximately 506,000 Bbls

compared to 574,000 Bbls produced during the comparable period of 2010. The increase in oil production volumes was primarily due to increases in

production at our Mississippi Canyon Block 109 and Ship Shoal Block 113 fields where we had development operations. The decrease in gas production

volumes was primarily due to natural production declines.

Prices. Prices realized during the year ended December 31, 2011 averaged $103.31 per Bbl of oil, $4.44 per Mcf of natural gas and $59.28 per Bbl of

NGLs, or 30% higher, on an Mcfe basis, than 2010 average realized prices of $73.14 per Bbl of oil, $5.12 per Mcf of natural gas and $47.86 per Bbl of

NGLs. All unit pricing amounts include the settlement of effective hedging contracts.

We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. During the year ended

December 31, 2011, effective hedging transactions increased our average realized natural gas price by $0.51 per Mcf and decreased our average realized oil

price by $5.09 per Bbl. During the year ended December 31, 2010, effective hedging transactions increased our average realized natural gas price by $0.94 per

Mcf and decreased our average realized oil price by $5.09 per Bbl.

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Revenue. Oil, natural gas and NGL revenue increased 32% to $864.6 million during the year ended December 31, 2011 from $656.1 million during

the year ended December 31, 2010. The increase was primarily due to a 41% increase in average realized oil prices along with a 12% increase in oil production

volumes, partially offset by a decline in average realized gas prices and gas production volumes.

Expenses. Lease operating expenses for the years ended December 31, 2011 and 2010 totaled $175.9 million and $150.2 million, respectively. On a

unit of production basis, lease operating expenses were $2.20 per Mcfe and $1.90 per Mcfe for the years ended December 31, 2011 and 2010, respectively.

The increase in lease operating expenses in 2011 was primarily attributable to increased platform and well maintenance.

For the year ended December 31, 2011, other operational expenses of $2.1 million included $0.7 million for the settlement of litigation associated with an

expensed operation in the first quarter of 2011, a $0.3 million loss on the sale of non-dedicated tubular inventory and $1.1 million of miscellaneous inventory

charges. For the year ended December 31, 2010, other operational expenses of $5.6 million included a $2.2 million loss on the sale of non-dedicated tubular

inventory and a total of $3.3 million of charges related to a delay in the drilling of the second well in our Amberjack drilling program as a result of the deep

water drilling moratorium.

DD&A expense on oil and gas properties for the year ended December 31, 2011 totaled $276.5 million, or $3.45 per Mcfe, compared to DD&A expense

of $242.7 million, or $3.08 per Mcfe, for the year ended December 31, 2010. The increase in DD&A expense in 2011 on a unit basis was primarily

attributable to the unit cost of current year net reserve additions (including future development costs) exceeding the per unit amortizable base as of the beginning

of the year. The average unit cost of the Pompano field deep water assets had a minimal impact on the DD&A rate because the acquisition occurred late in the

year.

For the years ended December 31, 2011 and 2010, incentive compensation expense totaled $11.6 million and $5.9 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, 2011 totaled $9.3 million, net of $42.0 million of capitalized interest, compared to interest expense of

$12.2 million, net of $30.8 million of capitalized interest, during the year ended December 31, 2010. The decrease in interest expense is primarily the result of

an increase in the amount of interest capitalized as a part of the cost of oil and gas properties.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Forward-Looking Statements

Certain of the statements set forth under this item and elsewhere in this Form 10-K are forward-looking and are based upon assumptions and anticipated

results that are subject to numerous risks and uncertainties. See “Item 1. Business – Forward-Looking Statements” and “Item 1A. Risk Factors.”

Accounting Matters and Critical Accounting Estimates

Fair Value Measurements. U.S. Generally Accepted Accounting Principles (“GAAP”), as codified, establish a framework for measuring fair value

and require certain disclosures about fair value measurements. There is an established fair value hierarchy that has three levels based on the reliability of the

inputs used to determine the fair value. These levels include: Level 1, defined 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, 2012, 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. Additionally, fair value concepts were applied in recording the acquisition

of various deep water assets in 2012 and 2011 and the acquisition of an office building in 2012.

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Business Combinations. Our acquisitions in 2012 and 2011 of various deep water assets were accounted for according to the guidance provided in

Accounting Standards Codification (“ASC”) 805, Business Combinations, which requires application of the acquisition method. This methodology requires

the recordation of net assets acquired and consideration transferred at fair value. Differences between the net fair value of assets acquired and consideration

transferred are recorded as goodwill or a bargain purchase gain.

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 evaluated properties and thereby subject to amortization. Sales of oil and gas

properties are accounted for as adjustments to the net full cost pool 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 (“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 the period reserves being determined by adding back production to end of the 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 salaries, general and administrative 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 and in the computation of DD&A

expense. 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, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved

reserves (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 for hedge

accounting treatment. We do not use derivative instruments for trading purposes. Instruments qualifying for hedge accounting treatment are recorded as an

asset or liability measured at fair value and subsequent changes in fair value are recognized in equity through other comprehensive income, net of related taxes,

to the extent the hedge is effective. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are

recognized in earnings.

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Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect

the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts

of revenue and expenses during the reporting period. Actual results could differ from those estimates. Our most significant estimates are:

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

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

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

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

• the effectiveness and estimated fair value of derivative positions;

• classification of unevaluated property costs;

• capitalized general and administrative costs and interest;

• insurance recoveries;

• 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

None.

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 income per share for 2012 would have decreased

approximately $1.22 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. Our hedging policy provides that not more than 50% of our estimated

production quantities can be hedged without the consent of the board of directors.

We have entered into fixed-price swaps with various counterparties for a portion of our expected 2013, 2014 and 2015 oil and natural gas production

from the Gulf Coast Basin. Some of our fixed-price oil swap settlements are based on an average of the NYMEX closing price for West Texas Intermediate

during the entire calendar month, and some are based on the average of the ICE closing price for Brent crude oil during the entire calendar month. Our fixedprice 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 to us if prices fall below the swap price. Our fixed-price swap contracts are with The Toronto-Dominion Bank,

Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia, Bank of America and Natixis.

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The following table illustrates our hedging positions for calendar years 2013, 2014 and 2015 as of February 21, 2013:

 

Fixed-Price Swaps

NYMEX (except where noted)

 Natural Gas Oil

 

Daily Volume

(MMBtus/d) 

Swap

Price ($) 

Daily 

Volume

(Bbls/d)

Swap

Price ($)

2013 10,000 4.000 1,000 92.80 

2013 10,000 5.270 2,000 * 94.05 

2013 10,000 5.320 1,000 94.45 

2013 1,000 94.60 

2013 1,000 97.15 

2013 1,000 101.53 

2013 1,000 103.00 

2013 1,000 103.15 

2013 1,000 104.25 

2013 1,000 104.47 

2013 1,000 104.50 

2013 1,000 † 107.30 

2014 10,000 4.000 1,000 90.06 

2014 10,000 4.040 1,000 93.55 

2014 10,000 4.105 1,000 94.00 

2014 10,000 4.250 1,000 98.00 

2014 1,000 98.30 

2014 1,000 99.65 

2014 1,000 † 103.30 

2015 10,000 4.005 1,000 90.00 

2015 10,000 4.220 

2015 10,000 4.255 

† Brent oil contract

* January through June

We believe these positions have hedged approximately 39% of our estimated 2013 production from estimated proved reserves, 34% of our estimated 2014

production from estimated proved reserves and 18% of our estimated 2015 production from estimated proved reserves.

Interest Rate Risk. We had total debt outstanding of $914.1 million at December 31, 2012, all of which bears interest at fixed rates. The $914.1

million of fixed-rate debt is comprised of $239.1 million ($300 million face value) of 2017 Convertible Notes, $375 million of 2017 Notes and $300 million

of 2022 Notes.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information concerning this Item begins on Page F-1.

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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 Annual

Report on Form 10-K.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including

our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as

defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Annual Report on 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, 2012 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, 2012 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, 2012. 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).

Based on our evaluation, we have concluded that our internal controls over financial reporting were effective as of December 31, 2012. 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, 2012.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

We have audited Stone Energy Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control

– Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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, 2012,

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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, cash flows

and changes in stockholders’ equity for each of the three years in the period ended December 31, 2012 and our report dated February 27, 2013 expressed an

unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 27, 2013

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ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The following table sets forth information regarding the names, ages (as of February 21, 2013) and positions held by each of our executive officers,

followed by biographies describing the business experience of our executive officers for at least the past five years. Our executive officers serve at the discretion

of the board of directors.

Name Age Position

David H. Welch 64 President, Chief Executive Officer and Director

Kenneth H. Beer 5 5 Executive Vice President and Chief Financial Officer

Andrew L. Gates, III 6 5 Senior Vice President, General Counsel and Secretary

Kevin G. Hurst 53 Vice President – GOM Shelf/Deep Gas

E. J. Louviere 64 Senior Vice President – Land

J. Kent Pierret 57 Senior Vice President, Chief Accounting Officer and Treasurer

Keith A. Seilhan 46 Vice President – Deep Water

Richard L. Toothman, Jr. 48 Vice President – Appalachia

Paul K. Wieg 54 Vice President – Exploration and Business Development

Florence M. Ziegler 52 Vice President – Human Resources and Administration

David H. Welch was appointed President, Chief Executive Officer and a director of the Company effective April 1, 2004. Prior to joining Stone,

Mr. Welch served as Senior Vice President of BP America, Inc. since 2003, and Vice President of BP, Inc. since 1999.

Kenneth H. Beer was named Executive Vice President and Chief Financial Officer in January 2011. Previously, he served as Senior Vice President and

Chief Financial Officer since August 2005. Prior to joining Stone, he served as a director of research and a senior energy analyst at the investment banking

firm of Johnson Rice & Company. Prior to joining Johnson Rice & Company in 1992, he was an energy analyst and investment banker at Howard Weil

Incorporated.

Andrew L. Gates, III was named Senior Vice President, General Counsel and Secretary in April 2004. He previously served as Vice President, General

Counsel and Secretary since August 1995.

Kevin G. Hurst was named Vice President – GOM Shelf/Deep Gas on February 1, 2013. He previously served as General Manager of Operations/GOM

Production from January 2012 through February 1, 2013. He served as Operations Manager – GOM Production from January 2011 through January 2012

and Production Manager from December 2007 through January 2011. Prior to joining Stone in 2007, he worked for MODEC, LLC as the General Manager for

FPSO/FSO Operations. Mr. Hurst has also worked for Southern Natural Gas Company/El Paso Energy Company and worked for 16 years for Arco serving

in various capacities.

E. J. Louviere was named Senior Vice President – Land in April 2004. Previously, he served as Vice President – Land since June 1995. He has been

employed by Stone since its inception in 1993.

J. Kent Pierret was named Senior Vice President, Chief Accounting Officer and Treasurer in April 2004. Mr. Pierret previously served as Vice President

and Chief Accounting Officer since June 1999 and Treasurer since February 2004.

Keith S. Seilhan was named Vice President – Deep Water on February 1, 2013. He previously served as Deep Water Projects Manager since joining

Stone in July 2012. Prior to joining Stone, Mr. Seilhan filled various senior leadership roles for Amoco and BP over his 21 year career. In his final year with

BP, he filled the role as BP’s Incident Commander on the Deepwater Horizon Incident in 2010 and also worked as an Emergency Response Consultant with

The Response Group for 1- / years. He has been an Asset Manager and Operations Manager for Deep Water Assets, Operations Director for Gulf of Mexico

and the Organizational Capability Manager. Mr. Seilhan received a “Wells Notice,” dated January 25, 2013, from the Staff of the SEC indicating its intent to

recommend to the SEC that it bring a civil injunctive action against Mr. Seilhan alleging that he violated Section 17(a) of the

41

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Securities Act, Section 10(b) of the Exchange Act and Rule 10b-5 thereunder. We have also been advised that Mr. Seilhan is a target of an investigation by the

Department of Justice (“DOJ”). The SEC’s inquiry and the DOJ’s investigation relate to activities prior to Mr. Seilhan’s employment with the Company and

are not directed at, and do not concern, the Company or any other member of management or any member of the board.

Richard L. Toothman, Jr. was named Vice President – Appalachia in May 2010. Prior to joining Stone in May 2010, he was employed by CNX Gas

Company in Bluefield, Virginia since August 2005 where he held two executive positions, VP Engineering and Technical Services and VP International

Business. He also worked for Consol Energy and Conoco in prior years.

Paul K. Wieg was named Vice President – Exploration and Business Development on February 1, 2013. He previously served as Director of

Geosciences/Deepwater Exploration Manager of Stone from January 2012 through February 1, 2013. He served as Director, Exploration and Geoscience

Technology from January 2011 through January 2012 and Deepwater Exploration Manager from July 2010 through January 2011. Prior to joining Stone in

2010, Mr. Wieg was Deepwater Exploration Manager for Eni Petroleum’s Gulf of Mexico business unit. He also served in various capacities for Dominion

E&P, CNG, Shell Offshore, Inc. Pecten International and Exxon USA.

Florence M. Ziegler was named Vice President – Human Resources and Administration in September 2005. She has been employed by Stone since its

inception in 1993 and served as the Director of Human Resources from 1997 to 2004.

Additional information required by Item 10, including information regarding our audit committee financial experts, is incorporated herein by reference to

such information as set forth in our definitive Proxy Statement for our 2013 Annual Meeting of Stockholders to be held on May 23, 2013. The Company has

made available free of charge on its Internet web-site ( 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.

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 2013

Annual Meeting of Stockholders to be held on May 23, 2013.

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 2013

Annual Meeting of Stockholders to be held on May 23, 2013.

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 2013

Annual Meeting of Stockholders to be held on May 23, 2013.

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 2013

Annual Meeting of Stockholders to be held on May 23, 2013.

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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, 2012 and 2011

Consolidated Statement of Operations for the three years in the period ended December 31, 2012

Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2012

Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2012

Consolidated Statement of Changes in Stockholders’ Equity for the three years in the period ended December 31, 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 on June 4, 1993, February 1, 2001 and February 19, 2002

(incorporated by reference to Exhibit 3.1 to the Registrant’s Quarterly Report on Form 10-Q filed August 7, 2012 (File

No.001-12074)).

 3.2

 

Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit

3.1 to the Registrant’s Current Report on Form 8-K filed May 21, 2008 (File No. 001-12074)).

 4.1

 

Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated

December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed

December 17, 2004 (File No. 001-12074)).

 4.2

 

First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and

JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to

Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed August 29, 2008 (File No. 001-12074)).

 4.3

 

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)).

 4.4

 

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)).

 4.5

 

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)).

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 4.6

 

Indenture related to the 1 / % 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 / % 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)).

 4.7

 

Second Supplemental Indenture, dated as of November 6, 2012, to the Indenture, dated as of December 15, 2004,

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 8, 2012 (File No. 001-12074)).

 4.8

 

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)).

 †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 Form 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)).

44

 3 4

 3 4
Table of Contents

 †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

 

$700,000,000 Third 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

April 26, 2011 (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the

quarter ended March 31, 2011 (File No. 001-12074)).

 10.14

 

Amendment No. 1 and Consent dated as of February 28, 2012 to the Third Amended and Restated Credit Agreement

(incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 5, 2012 (File No.

001-12074)).

 10.15

 

Amendment No. 2 and Consent dated as of October 22, 2012 to the Third Amended and Restated Credit Agreement

(incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed October 22, 2012 (File

No. 001-12074)).

 10.16

 

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)).

 10.17

 

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)).

 10.18

 

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)).

 10.19

 

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)).

 10.20

 

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)).

 10.21

 

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)).

 10.22

 

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)).

 10.23

 

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)).

45
Table of Contents

 10.24

 

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)).

 10.25

 

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)).

 10.26

 

Amendment to Base Warrant Confirmation and Additional Warrant Confirmation dated March 5, 2012, by and

between Stone Energy Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.10 to the

Registrant’s Current Report on Form 8-K filed March 6, 2012 (File No. 001-12074)).

 *21.1 Subsidiaries of the Registrant.

 *23.1 Consent of Independent Registered Public Accounting Firm.

 *23.2 Consent of Netherland, Sewell & Associates, Inc.

 *31.1

 

Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the

Securities Exchange Act of 1934.

 *31.2

 

Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the

Securities Exchange Act of 1934.

 *#32.1

 

Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18

U.S.C. § 1350.

**101.INS XBRL Instance Document

**101.SCH XBRL Schema Document

**101.CAL XBRL Calculation Linkbase Document

**101.DEF XBRL Definition Linkbase Document

**101.LAB XBRL Label Linkbase Document

**101.PRE XBRL Presentation Linkbase Document

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

* Filed or furnished herewith.

** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data

file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not

filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

# 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.

46
Table of Contents

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 27, 2013 By: /s/ David H. Welch

David H. Welch

President and

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the

registrant and in the capacities and on the dates indicated.

Signature Title Date

/s/ David H. Welch President, Chief Executive Officer and Director February 27, 2013

David H. Welch (principal executive officer)

/s/ Kenneth H. Beer

 Executive Vice President and Chief Financial Officer February 27, 2013

Kenneth H. Beer (principal financial officer)

/s/ J. Kent Pierret

 Senior Vice President, Chief February 27, 2013

J. Kent Pierret

 

Accounting Officer and Treasurer

(principal accounting officer)

/s/ George R. Christmas

 Director February 27, 2013

George R. Christmas 

/s/ B.J. Duplantis

 Director February 27, 2013

B.J. Duplantis 

/s/ Peter D. Kinnear

 Director February 27, 2013

Peter D. Kinnear 

/s/ John P. Laborde

 Director February 27, 2013

John P. Laborde 

/s/ Robert S. Murley Director February 27, 2013

Robert S. Murley 

/s/ Richard A. Pattarozzi

 Director February 27, 2013

Richard A. Pattarozzi 

/s/ Donald E. Powell

 Director February 27, 2013

Donald E. Powell 

/s/ Kay G. Priestly Director February 27, 2013

Kay G. Priestly 

/s/ Phyllis M. Taylor

 Director February 27, 2013

Phyllis M. Taylor 

47
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INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm F-2 

Consolidated Balance Sheet as of December 31, 2012 and 2011 F-3 

Consolidated Statement of Operations for the years ended December 31, 2012, 2011 and 2010 F-4 

Consolidated Statement of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010 F-5 

Consolidated Statement of Cash Flows for the years ended December 31, 2012, 2011 and 2010 F-6 

Consolidated Statement of Changes in Stockholders’ Equity for the years ended December 31, 2012, 2011 and 2010 F-7 

Notes to Consolidated Financial Statements F-8 

F-1
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

We have audited the accompanying consolidated balance sheets of Stone Energy Corporation as of December 31, 2012 and 2011, and the related consolidated

statements of operations, comprehensive income, cash flows, and changes in stockholders’ equity for each of the three years in the period ended December 31,

2012. 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended

December 31, 2012, 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, 2012, based on criteria established in Internal Control – Integrated Framework issued by the

Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 27, 2013

F-2
Table of Contents

STONE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

(Amounts in thousands of dollars, except per share amounts)

 December 31,

 2012 2011

Assets 

Current assets: 

Cash and cash equivalents $ 279,526 $ 38,451 

Accounts receivable 167,288 118,139 

Fair value of hedging contracts 39,655 25,177 

Current income tax receivable 10,027 19,946 

Deferred taxes 15,514 26,072 

Inventory 4,207 4,643 

Other current assets 3,626 791 

Total current assets 519,843 233,219 

Oil and gas properties, full cost method of accounting: 

Proved 7,244,466 6,648,168 

Less: accumulated depreciation, depletion and amortization (5,510,166) (5,174,729) 

Net proved oil and gas properties 1,734,300 1,473,439 

Unevaluated 447,795 401,609 

Other property and equipment, net of accumulated depreciation of $26,429 and $24,263, respectively 22,115 11,172 

Fair value of hedging contracts 9,199 22,543 

Other assets, net of accumulated depreciation and amortization of $6,438 and $5,911, respectively 43,179 23,769 

Total assets $ 2,776,431 $2,165,751 

Liabilities and Stockholders’ Equity 

Current liabilities: 

Accounts payable to vendors $ 94,361 $ 102,946 

Undistributed oil and gas proceeds 23,414 27,328 

Accrued interest 18,546 14,059 

Fair value of hedging contracts 149 11,122 

Asset retirement obligations 66,260 62,676 

Other current liabilities 16,765 28,370 

Total current liabilities 219,495 246,501 

Long-term debt 914,126 620,000 

Deferred taxes 310,830 247,835 

Asset retirement obligations 422,042 363,103 

Fair value of hedging contracts 1,530 815 

Other long-term liabilities 36,275 19,668 

Total liabilities 1,904,298 1,497,922 

Commitments and contingencies 

Stockholders’ equity: 

Common stock, $.01 par value; authorized 100,000,000 shares; issued 48,392,552 and 48,076,860 shares,

respectively 484 481 

Treasury stock (16,582 shares, at cost) (860) (860) 

Additional paid-in capital 1,386,475 1,338,565 

Accumulated deficit (542,799) (692,225) 

Accumulated other comprehensive income 28,833 21,868 

Total stockholders’ equity 872,133 667,829 

Total liabilities and stockholders’ equity $ 2,776,431 $2,165,751 

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

F-3
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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(Amounts in thousands, except per share amounts)

 Year Ended December 31,

 2012 2011 2010

Operating revenue: 

Oil production $ 761,304 $663,958 $ 417,948 

Gas production 134,739 170,611 210,686 

Natural gas liquids production 48,498 29,996 27,473 

Other operational income 3,520 3,938 5,916 

Derivative income, net 3,428 1,418 3,265 

Total operating revenue 951,489 869,921 665,288 

Operating expenses: 

Lease operating expenses 215,003 175,881 150,212 

Transportation, processing and gathering expenses 21,782 8,958 7,218 

Production taxes 10,015 9,380 5,808 

Depreciation, depletion and amortization 344,365 280,020 248,201 

Accretion expense 33,331 30,764 34,469 

Salaries, general and administrative expenses 54,648 40,169 42,759 

Incentive compensation expense 8,113 11,600 5,888 

Other operational expenses 267 2,149 5,579 

Total operating expenses 687,524 558,921 500,134 

Income from operations 263,965 311,000 165,154 

Other (income) expenses: 

Interest expense 30,375 9,289 12,192 

Interest income (600) (420) (1,464) 

Other income (1,805) (1,942) (776) 

Other expense — — 671 

Loss on early extinguishment of debt 1,972 607 1,820 

Total other expenses 29,942 7,534 12,443 

Net income before income taxes 234,023 303,466 152,711 

Provision (benefit) for income taxes: 

Current 15,022 (20,386) 5,808 

Deferred 69,575 129,520 50,474 

Total income taxes 84,597 109,134 56,282 

Net income $ 149,426 $ 194,332 $ 96,429 

Basic earnings per share $ 3.03 $ 3.97 $ 1.99 

Diluted earnings per share $ 3.03 $ 3.97 $ 1.99 

Average shares outstanding 48,319 47,988 47,681 

Average shares outstanding assuming dilution 48,361 48,030 47,706 

The accompanying notes are an integral part of this statement.

F-4
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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Amounts in thousands of dollars)

 Year Ended December 31,

 2012 2011 2010

Net income $ 149,426 $194,332 $96,429 

Other comprehensive income net of tax effect: 

Adjustment for fair value accounting of derivatives 6,965 36,072 1,176 

Comprehensive income $156,391 $ 230,404 $97,605 

The accompanying notes are an integral part of this statement.

F-5
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STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Amounts in thousands of dollars)

 Year Ended December 31,

 2012 2011 2010

Cash flows from operating activities: 

Net income $ 149,426 $ 194,332 $ 96,429 

Adjustments to reconcile net income to net cash provided by operating activities: 

Depreciation, depletion and amortization 344,365 280,020 248,201 

Accretion expense 33,331 30,764 34,469 

Deferred income tax provision 69,575 129,520 50,474 

Settlement of asset retirement obligations (65,567) (63,391) (36,901) 

Non-cash stock compensation expense 8,699 5,905 5,692 

Excess tax benefits (949) (1,493) (299) 

Non-cash derivative income (509) (2,216) (324) 

Loss on early extinguishment of debt 1,972 607 1,820 

Non-cash interest expense 13,085 1,908 858 

Other non-cash (income) expense — (1,602) 979 

Change in current income taxes 10,618 (19,451) (10,871) 

(Increase) decrease in accounts receivable (55,871) (19,600) 49,633 

(Increase) decrease in other current assets (2,836) (66) 74 

Decrease in inventory 436 1,619 2,123 

Increase (decrease) in accounts payable 5,101 6,039 (773) 

Increase (decrease) in other current liabilities (10,426) 29,583 (18,088) 

Other 9,299 (1,628) 1,298 

Net cash provided by operating activities 509,749 570,850 424,794 

Cash flows from investing activities: 

Investment in oil and gas properties (555,855) (764,933) (401,767) 

Proceeds from sale of oil and gas properties, net of expenses 403 87,930 31,635 

Sale of fixed assets 134 — — 

Investment in fixed and other assets (13,370) (2,247) (2,949) 

Acquisition of non-controlling interest in subsidiary — — (1,007) 

Net cash used in investing activities (568,688) (679,250) (374,088) 

Cash flows from financing activities: 

Proceeds from bank borrowings 25,000 75,000 — 

Repayments of bank borrowings (70,000) (30,000) (175,000) 

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 300,000 — 375,000 

Deferred financing costs (11,966) (4,017) (11,474) 

Redemption of senior subordinated notes (200,681) — (200,503) 

Excess tax benefits 949 1,493 299 

Net payments for share based compensation (3,773) (2,581) (1,365) 

Net cash provided by (used in) financing activities 300,014 39,895 (13,043) 

Net change in cash and cash equivalents 241,075 (68,505) 37,663 

Cash and cash equivalents, beginning of year 38,451 106,956 69,293 

Cash and cash equivalents, end of year $ 279,526 $ 38,451 $ 106,956 

Supplemental cash flow information:

Cash (paid) refunded during the year for:

 

Interest, net of amount capitalized ($ 20,150) ($ 9,808) ($ 8,760) 

Income taxes (4,405) 935 (26,525) 

The accompanying notes are an integral part of this statement.

F-6
Table of Contents

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Amounts in thousands of dollars)

 

Common

Stock 

Treasury

Stock

Additional

Paid-In

Capital

Retained

Earnings

Accumulated

Other

Comprehensive

Income (Loss)

Total

Stockholders’

Equity

Balance, December 31, 2009 $ 475 ($ 860) $ 1,324,410 ($ 982,986) ($ 15,380) $325,659 

Net income — — — 96,429 — 96,429 

Adjustment for fair value accounting of derivatives, net of tax — — — — 1,176 1,176 

Exercise of stock options and vesting of restricted stock 3 — (1,370) — — (1,367) 

Amortization of stock compensation expense expense — — 8,462 — — 8,462 

Net tax deficit from stock option exercises and restricted stock

vesting — — (2) — — (2) 

Balance, December 31, 2010 478 (860) 1,331,500 (886,557) (14,204) 430,357 

Net income — — — 194,332 — 194,332 

Adjustment for fair value accounting of derivatives, net of tax — — — — 36,072 36,072 

Exercise of stock options and vesting of restricted stock 3 — (2,584) — — (2,581) 

Amortization of stock compensation expense expense — — 8,914 — — 8,914 

Net tax benefit from stock option exercises and restricted stock

vesting — — 735 — — 735 

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 expense — — 12,792 — — 12,792 

Net tax benefit 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 

The accompanying notes are an integral part of this statement.

F-7
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STONE ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Amounts 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 have been operating in the Gulf Coast Basin since our incorporation in 1993 and have established a technical and

operational expertise in this area. We have expanded our reserve base outside of the conventional shelf of the Gulf of Mexico (“GOM”) and into the more prolific

reserve basins of the GOM deep water and Gulf Coast deep gas, as well as onshore oil and gas shale opportunities, including the Marcellus Shale in

Appalachia. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette,

Louisiana 70508. We have additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia.

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

Basis of Presentation:

The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Energy Offshore, L.L.C. (“Stone Offshore”),

Stone Energy, L.L.C. and Caillou Boca Gathering, LLC (“Caillou Boca”). On September 6, 2012, Caillou Boca was merged into Stone Offshore. On

December 31, 2010, Stone Energy, L.L.C. was merged into Stone Offshore. All intercompany balances have been eliminated. Certain prior year amounts have

been reclassified to conform to current year presentation.

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, cost to abandon oil and gas properties, 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 positions, 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, 2012

and 2011, 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. Additionally, fair value concepts were applied in recording the acquisition of various deep

water assets in December 2011 and June 2012 and the acquisition of an office building in December 2012.

Hybrid Debt Instruments:

In 2012, we issued $300,000 in aggregate principal amount of 1 / % Senior Convertible Notes due 2017 (the “2017 Convertible Notes”). See Note 11 –

Long-Term Debt. On that same day we entered into convertible note hedging transactions which are expected to reduce the potential dilution to our common

stock 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 equity, and accretion of the resulting discount as part of interest expense.

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

F-8

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Table of Contents

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.

Business Combinations:

Our acquisitions in 2012 and 2011 of various deep water assets were accounted for according to the guidance provided in ASC 805, Business

Combinations, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and consideration

transferred at fair value. Differences between the net fair value of assets acquired and consideration transferred are recorded as goodwill or a bargain purchase

gain.

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 and in the computation of DD&A

expense. 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.

We amortize our investment in oil and gas properties through DD&A expense using the units of production (“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 the period reserves being determined by adding back production to end of the 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 (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties net of related deferred taxes.

We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows

from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows.

Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized, unless the adjustment would

significantly alter the relationship between capitalized costs and proved reserves.

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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 life 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.

Earnings Per Common Share:

Under U.S. GAAP, certain instruments granted in share based payment transactions are 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 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 purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures, including

future abandonment costs, related to evaluated projects are capitalized and depreciated, depleted and amortized on the UOP method. For income tax purposes,

only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion, although for 2011 and

2012, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged

to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where

management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for

sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and

different reporting methods for employee compensation.

Derivative Instruments and Hedging Activities:

The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments that qualify for cash flow

hedge accounting treatment with contemporaneous documentation are recorded as an asset or liability measured at fair value and subsequent changes in fair

value are recognized in equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Additionally,

monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flow from operating activities. Instruments not qualifying

for hedge accounting treatment are recorded in the balance sheet at fair value and changes in fair value are recognized in earnings through derivative expense

(income).

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Stock-Based Compensation:

We record stock-based compensation based on 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,

 2012 2011 2010

Income (numerator): 

Basic: 

Net income $149,426 $ 194,332 $96,429 

Net income attributable to participating securities (2,984) (3,670) (1,559) 

Net income attributable to common stock – basic $ 146,442 $190,662 $ 94,870 

Diluted: 

Net income $149,426 $ 194,332 $96,429 

Net income attributable to participating securities (2,982) (3,667) (1,558) 

Net income attributable to common stock – diluted $ 146,444 $190,665 $ 94,871 

Weighted average shares (denominator): 

Weighted average shares – basic 48,319 47,988 47,681 

Diluted effect of stock options 42 42 25 

Weighted average shares – diluted 48,361 48,030 47,706 

Basic income per common share $ 3.03 $ 3.97 $ 1.99 

Diluted income per common share $ 3.03 $ 3.97 $ 1.99 

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 347,000, 374,000 and 420,000 shares during the years ended December 31, 2012, 2011 and 2010, respectively.

During the years ended December 31, 2012, 2011 and 2010, approximately 316,000, 312,000 and 255,000 shares of common stock, respectively, were

issued from authorized shares upon the vesting (lapse of forfeiture restrictions) of restricted stock by employees and nonemployee directors.

Because it is management’s stated intention to redeem the principal amount of our 2017 Convertible Notes (see Note 11 – Long-Term Debt) in cash, we

have used the treasury method for determining potential dilution in the diluted earnings per share computation. Since the average price of our common stock

was less than the effective conversion price for such notes during the reporting period, the 2017 Convertible Notes were not dilutive for such period.

Additionally, since the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 11 – Long-Term Debt) for

the reporting period, such warrants were also not dilutive for such period.

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NOTE 3 — ACCOUNTS RECEIVABLE:

In our capacity as operator for our co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests.

We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable are comprised of the

following amounts:

 As of December 31,

 2012 2011

Other co-venturers $ 16,735 $ 8,890 

Trade 130,448 91,959 

Insurance receivable — 4,236 

Unbilled accounts receivable 20,053 13,009 

Other 52 45 

 $167,288 $118,139 

We have accrued insurance receivables to the extent we have concluded the insurance recovery is probable. The accrual only relates to costs previously

recorded in our financial statements, including asset retirement obligations and repair expenses included in lease operating expenses.

NOTE 4 — 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 years ended:

 December 31,

 2012 2011 2010

Conoco, Inc.

 13% 28% 26% 

Hess Corporation (a) (a) 11% 

Phillips 66 Company 18% (a) (a) 

Sequent Energy Management LP (a) (a) 10% 

Shell Trading (US) Company 41% 46% 40% 

(a) Less than 10 percent.

The maximum amount of credit risk exposure at December 31, 2012 relating to these customers amounted to $83,432.

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

Approximately18% of our estimated proved reserves (unaudited) at December 31, 2012 and 56% of our production during 2012 were associated with

our Gulf Coast Basin conventional shelf properties. Approximately 38% of our estimated proved reserves (unaudited) at December 31, 2012 and 27% of our

production during 2012 were associated with our GOM deep water and deep shelf gas properties.

Cash and Cash Equivalents

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

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NOTE 5 — ACQUISITIONS AND DIVESTITURES:

Acquisitions

In December 2012, we closed on the acquisition of an office building. The acquisition was accounted for according to the guidance provided in ASC

805, Business Combinations, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and

consideration transferred at fair value. See Note 8 – Fair Value Measurements. Differences between the net fair value of assets acquired and consideration

transferred are recorded as goodwill or a bargain purchase gain. The building and land were recorded at fair value of $8,539. Consideration transferred in the

transaction was $8,539 in cash, resulting in no goodwill or bargain purchase gain.

On June 18, 2012, we completed the acquisition of a 25% working interest in the five block deep water Pompano field in Mississippi Canyon, an

approximate 14% working interest in Mississippi Canyon Block 29 and a 10% working interest in certain aliquots of Mississippi Canyon Block 72. The

acquisition was also accounted for according to the guidance provided in ASC 805, Business Combinations. Consideration transferred in the transaction was

$26,398 in cash, resulting in no goodwill or bargain purchase gain. The following represents the allocation of the recorded value of net assets acquired in the

transaction.

Proved oil and gas properties $39,221 

Unevaluated oil and gas properties 1,637 

Asset retirement obligations (14,460) 

Total fair value of net assets $26,398 

On December 28, 2011, we completed the acquisition of BP Exploration & Production Inc.’s (“BP”) 75% operated working interest in the five block

deep water Pompano field in Mississippi Canyon, a 51% operated working interest in the adjacent Mississippi Canyon Block 29, a 50% non-operated

working interest in the Mica field, which ties back to the Pompano platform and a 75% interest in 23 deep water exploration leases located in the vicinity of the

Pompano field. The acquisition was also accounted for according to the guidance provided in ASC 805, Business Combinations. Consideration transferred in

the transaction was $167,631 in cash, resulting in no goodwill or bargain purchase gain. The following represents the allocation of the recorded value of net

assets acquired in the transaction.

Proved oil and gas properties $ 208,680 

Unevaluated oil and gas properties 17,314 

Asset retirement obligations (58,363) 

Total fair value of net assets $167,631 

The following unaudited summary pro forma combined statement of operations data of Stone for the year ended December 31, 2011 has been prepared

to give effect to the acquisition of the deep water assets from BP as if it had occurred on January 1, 2010. The pro forma financial information is not

necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2010 and is not intended to be a projection of future

results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production

declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors.

 

Year Ended

December 31, 2011

 (Unaudited)

Revenues $ 1,007,376 

Income from operations 392,054 

Net income 242,118 

Basic earnings per share $ 4.95 

Diluted earnings per share $ 4.95 

In January 2011, we completed the acquisition of an additional 15% working interest in the Pyrenees project at a cost of approximately $14,974,

bringing our ownership up to a 30% working interest. In December 2011, we completed the acquisition of a 25% non-operated working interest in the deep

water Wideberth development project at a cost of approximately $31,000 and the assumption of approximately $1,078 of asset retirement obligations. During

the second half of 2011, we added approximately 10,000 net acres to our West Virginia leasehold position, including the acquisition of over 6,700 net acres

from a single entity at a cost of approximately $19,000.

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Divestitures

In the fourth quarter of 2011, we completed the sale of our non-operated interest in the Main Pass Block 296 and 311 fields to two separate parties for

total cash consideration of approximately $80,381 and the assumption by the third parties of the associated asset retirement obligation of approximately

$10,900. The sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

NOTE 6 — INVESTMENT IN OIL AND GAS PROPERTIES:

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,

 2012 2011 2010

Oil and gas properties, proved and unevaluated: 

Balance, beginning of year $ 7,049,777 $ 6,202,758 $ 5,741,081 

Costs incurred during the year (capitalized): 

Acquisition costs, net of sales of unevaluated properties 102,807 270,354 127,069 

Exploratory costs 81,458 84,199 42,205 

Development costs (1) 395,555 426,355 241,387 

Salaries, general and administrative costs 25,318 24,430 20,521 

Interest 37,656 42,033 30,783 

Less: overhead reimbursements (310) (352) (288) 

Total costs incurred during the year, net of divestitures 642,484 847,019 461,677 

Balance, end of year $ 7,692,261 $ 7,049,777 $ 6,202,758 

Accumulated depreciation, depletion and amortization (DD&A): 

Balance, beginning of year ($5,174,729) ($ 4,804,949) ($4,555,372) 

Provision for DD&A (341,096) (276,480) (242,745) 

Sale of proved properties 5,659 (93,300) (6,832) 

Balance, end of year ($5,510,166) ($5,174,729) ($ 4,804,949) 

Net capitalized costs, proved and unevaluated $ 2,182,095 $ 1,875,048 $ 1,397,809 

DD&A per Mcfe $ 3.69 $ 3.45 $ 3.08 

(1) Includes capitalized asset retirement costs of $95,293, $96,386 and $56,444, respectively. 

Costs incurred during the year (expensed): 

Lease operating expenses $ 215,003 $ 175,881 $ 150,212 

Transportation, processing and gathering expenses 21,782 8,958 7,218 

Production taxes 10,015 9,380 5,808 

Accretion expense 33,331 30,764 34,469 

Expensed costs $ 280,131 $ 224,983 $ 197,707 

The following table discloses net costs incurred (evaluated) on our unevaluated properties:

 Year Ended December 31,

 2012 2011 2010

Unevaluated oil and gas properties: 

Net costs incurred (evaluated) during year: 

Acquisition costs $ 9,739 ($ 2,397) $42,664 

Exploration costs (1,209) (51,207) 10,491 

Capitalized interest 37,656 42,033 30,783 

 $46,186 ($11,571) $83,938 

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The following table discloses financial data associated with unevaluated costs at December 31, 2012:

 Balance as of 

Net Costs Incurred During the

Year Ended December 31,

 

December 31,

2012 2012 2011 2010 

2009

and prior

Acquisition costs $258,580 $ 43,544 $39,984 $104,154 $ 70,898 

Exploration costs 108,248 81,246 2,335 5,151 19,516 

Capitalized interest 80,967 30,989 27,818 13,762 8,398 

Total unevaluated costs $447,795 $155,779 $ 70,137 $123,067 $ 98,812 

Approximately 124 specifically identified drilling projects are included in unevaluated costs at December 31, 2012 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, 2012, 2011 and 2010 totaled $37,656, $42,033 and

$30,783, respectively.

NOTE 7 — DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

Our hedging strategy is designed to protect our near and intermediate term cash flow 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 hedging transactions to secure a commodity price for a portion of future production that is acceptable at the time of the transaction. These

hedges are designated as cash flow hedges upon entering into the contract. We do not enter into hedging transactions for trading purposes. We have no fair

value hedges.

The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. If the instrument qualifies for hedge

accounting treatment, 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

equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Additionally, monthly settlements of

effective hedges are reflected in revenue from oil and gas production and cash flows from operations. Instruments not qualifying for hedge accounting are

recorded in the balance sheet at fair value and changes in fair value are recognized in earnings through derivative expense (income). Typically, a small portion

of our derivative contracts are determined to be ineffective. This is 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. Monthly settlements of ineffective hedges are recognized in

earnings through derivative expense (income) and cash flows from operations.

We have entered into fixed-price swaps with various counterparties for a portion of our expected 2013, 2014 and 2015 oil and natural gas production

from the Gulf Coast Basin. Some of our fixed-price oil swap settlements are based on an average of the New York Mercantile Exchange (“NYMEX”) closing

price for West Texas Intermediate during the entire calendar month, and some are based on the average of the Intercontinental Exchange closing price for Brent

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 to us if prices fall below the swap price. Our fixed-price swap

contracts are with The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia, Bank of America and Natixis .

All of our derivative instruments at December 31, 2012, 2011 and 2010 were designated as effective cash flow hedges; however, during the years ended

December 31, 2012, 2011 and 2010, certain of our derivative contracts were determined to be partially ineffective. The following tables disclose the location

and fair value amounts of derivative instruments reported in our balance sheet at December 31, 2012 and December 31, 2011.

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Fair Value of Derivative Instruments at December 31, 2012

 Asset Derivatives Liability Derivatives

Description Balance Sheet Location Fair Value Balance Sheet Location Fair Value

Commodity contracts

 

Current assets: Fair value of hedging

contracts

 $39,655 

Current liabilities: Fair value of

hedging contracts ($ 149) 

 

Long-term assets: Fair value of

hedging contracts 9,199 

Long-term liabilities: Fair value of

hedging contracts (1,530) 

 $ 48,854 ($1,679) 

Fair Value of Derivative Instruments at December 31, 2011

 Asset Derivatives Liability Derivatives

Description Balance Sheet Location Fair Value Balance Sheet Location Fair Value

Commodity contracts

 

Current assets: Fair value of hedging

contracts

 $25,177 

Current liabilities: Fair value of

hedging contracts ($11,122) 

 

Long-term assets: Fair value of

hedging contracts 22,543 

Long-term liabilities: Fair value of

hedging contracts (815) 

 $ 47,720 ($11,937) 

The following table discloses the effect of derivative instruments in the statement of operations for the years ended December 31, 2012, 2011 and 2010.

The Effect of Derivative Instruments on the Statement of Operations for the Years Ended December 31, 2012, 2011 and 2010

Derivatives in Cash Flow Hedging

Relationships 

Amount of Gain

Recognized in

OCI on

Derivative (a) 

Gain (Loss) Reclassified from

Accumulated OCI into Income

(Effective Portion) (b)

Gain Recognized in Income on Derivative

(Ineffective Portion)

 Location Location 

 2012 2012 2012

Commodity contracts $ 6,965 

Operating revenue - oil/gas

production $ 30,326 Derivative income, net $ 3,428 

Total $ 6,965 $ 30,326 $ 3,428 

 2011 2011 2011

Commodity contracts $ 36,072 

Operating revenue - oil/gas

production ($13,274) Derivative income, net $ 1,418 

Total $ 36,072 ($13,274) $ 1,418 

 2010 2010 2010

Commodity contracts $ 1,176 

Operating revenue - oil/gas

production $ 9,631 Derivative income, net $3,265 

Total $ 1,176 $ 9,631 $3,265 

(a) Net of related tax effect of $3,918, $20,290 and $292 for the years ended December 31, 2012, 2011 and 2010, respectively.

(b) For the year ended December 31, 2012, effective hedging contracts increased oil revenue by $8,546 and increased gas revenue by $21,780. For the year

ended December 31, 2011, effective hedging contracts decreased oil revenue by $32,706 and increased gas revenue by $19,432. For the year ended

December 31, 2010, effective hedging contracts decreased oil revenue by $29,047 and increased gas revenue by $38,678.

At December 31, 2012, we had accumulated other comprehensive income of $28,833 net of tax, which related to the fair value of our swap contracts

that were outstanding as of December 31, 2012. We believe that approximately $24,033 of the accumulated other comprehensive income will be reclassified into

earnings in the next 12 months.

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The following table illustrates our hedging positions for calendar years 2013, 2014 and 2015 as of February 21, 2013:

 

Fixed-Price Swaps

NYMEX (except where noted)

 Natural Gas Oil

 

Daily Volume

(MMBtus/d) 

Swap

Price ($) 

Daily Volume

(Bbls/d)

Swap

Price ($)

2013 10,000 4.000 1,000 92.80 

2013 10,000 5.270 2,000* 94.05 

2013 10,000 5.320 1,000 94.45 

2013 1,000 94.60 

2013 1,000 97.15 

2013 1,000 101.53 

2013 1,000 103.00 

2013 1,000 103.15 

2013 1,000 104.25 

2013 1,000 104.47 

2013 1,000 104.50 

2013 1,000† 107.30 

2014 10,000 4.000 1,000 90.06 

2014 10,000 4.040 1,000 93.55 

2014 10,000 4.105 1,000 94.00 

2014 10,000 4.250 1,000 98.00 

2014 1,000 98.30 

2014 1,000 99.65 

2014 1,000† 103.30 

2015 10,000 4.005 1,000 90.00 

2015 10,000 4.220 

2015 10,000 4.255 

† Brent oil contract

* January through June

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, 2012 and December 31, 2011, 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,

see Note 7 – Derivative Instruments and Hedging Activities . We used the market approach in determining the fair value of our investments in marketable

securities, which are included within the Level 1 fair value hierarchy.

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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, 2012:

 Fair Value Measurements at December 31, 2012

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 $ 13,492 $ 13,492 $ — $ — 

Hedging contracts 48,854 — 48,854 — 

Total $ 62,346 $ 13,492 $ 48,854 $ — 

 Fair Value Measurements at December 31, 2012

Liabilities Total

Quoted Prices in

Active Markets for

Identical Liabilities

(Level 1) 

Significant Other

Observable

Inputs

(Level 2)

Significant

Unobservable

Inputs

(Level 3)

Hedging contracts ($ 1,679) $ — ($ 1,679) $ — 

Total ($ 1,679) $ — ($ 1,679) $ — 

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2011:

 Fair Value Measurements at December 31, 2011

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 $ 11,961 $ 11,961 $ — $ — 

Hedging contracts 47,720 — 47,720 — 

Total $ 59,681 $ 11,961 $ 47,720 $ — 

 Fair Value Measurements at December 31, 2011

Liabilities Total

Quoted Prices in

Active Markets for

Identical Liabilities

(Level 1) 

Significant Other

Observable

Inputs

(Level 2)

Significant

Unobservable

Inputs

(Level 3)

Hedging contracts ($ 11,937) $ — ($ 11,937) $ — 

Total ($ 11,937) $ — ($ 11,937) $ — 

The fair value of cash and cash equivalents and our variable-rate bank debt approximated book value at December 31, 2012 and 2011. As of

December 31, 2012 and 2011, the fair value of our 8 / % Senior Notes due 2017 (the “2017 Notes”) was approximately $401,250 and $386,250,

respectively. As of December 31, 2011, the fair value of our 6 / % Senior Subordinated Notes due 2014 (the “2014 Notes”) was approximately $199,000. On

December 17, 2012, our 2014 Notes were fully redeemed. As of December 31, 2012, the fair value of the liability component of our 2017 Convertible Notes

was approximately $249,601. As of December 31, 2012, the fair value of our 7 / % Senior Notes due 2022 (the “2022 Notes”) was approximately $314,250.

The fair value of our outstanding notes was determined based upon quotes obtained from brokers, which represent Level 2 inputs.

We applied fair value concepts in determining the liability component of our 2017 Convertible Notes (see Note 11 – Long-Term Debt) at inception and

at December 31, 2012. 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.

We applied fair value concepts in the recording of various deep water assets acquired in 2011 and 2012. See Note 5 – Acquisitions and Divestitures.

The fair value of proved and unevaluated oil and gas properties was estimated using a market approach. Significant inputs were market value comparisons

for similar transactions within a one-year period. These inputs were considered Level 3 inputs. Asset retirement obligations were determined in accordance with

applicable accounting standards.

We applied fair value concepts in recording the acquisition of an office building in 2012. See Note 5 – Acquisitions and Divestitures. The fair value

of the building was estimated using an income approach. Significant inputs used in this approach were anticipated future earnings (Level 2) and an expected

rate of return (Level 3).

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NOTE 9 — ASSET RETIREMENT OBLIGATIONS:

The change in our asset retirement obligations during 2012, 2011 and 2010 is set forth below:

 Year Ended December 31,

 2012 2011 2010

Asset retirement obligations as of the beginning of the year, including current

portion $425,779 $ 373,920 $320,599 

Liabilities incurred 3,869 7,993 1,528 

Liabilities settled (67,641) (63,226) (36,392) 

Liabilities assumed 15,263 59,441 — 

Divestment of properties (7,563) (10,900) (692) 

Accretion expense 33,331 30,764 34,469 

Revision of estimates 85,264 27,787 54,408 

Asset retirement obligations as of the end of the year, including current portion $ 488,302 $425,779 $ 373,920 

NOTE 10 — INCOME TAXES:

An analysis of our deferred taxes follows:

 As of December 31,

 2012 2011

Tax effect of temporary differences: 

Oil and gas properties – full cost ($465,862) ($ 381,413) 

Asset retirement obligations 175,788 153,281 

Stock compensation 5,588 4,962 

Hedges (16,983) (12,882) 

Alternative minimum tax credit carryforward — 5,358 

Other 6,153 8,931 

 ($295,316) ($221,763) 

We estimate that we have approximately $15,022, ($20,386) and $5,808 of current federal income tax expense (benefit) for the years ended

December 31, 2012, 2011 and 2010, respectively. We have a $10,027 and $19,946 current income tax receivable at December 31, 2012 and 2011,

respectively.

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,

 2012 2011 2010

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 0.6 0.3 — 

Other (0.5) (0.3) 0.9 

Effective income tax rate 36.1% 36.0% 36.9% 

In 2012 and 2010, we recognized a tax deduction for domestic production activities pursuant to Internal Revenue Code Section 199.

Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to $3,918, $20,290 and $292 for the years

ended December 31, 2012, 2011 and 2010, respectively.

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As of December 31, 2012 and 2011, we had unrecognized tax benefits of $385. If recognized, all of our unrecognized tax benefits as of December 31,

2012 would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows:

Total unrecognized tax benefits as of December 31, 2011 $385 

Increases (decreases) in unrecognized tax benefits as a result of: — 

Tax positions taken during a prior period — 

Tax positions taken during the current period — 

Settlements with taxing authorities — 

Lapse of applicable statute of limitations — 

Total unrecognized tax benefits as of December 31, 2012 $385 

Our unrecognized tax benefits pertain to proposed state income tax audit adjustments. We believe that our unrecognized tax benefits may be reduced to

zero within the next 12 months upon completion and ultimate settlement of the state exams or litigation.

It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative

expenses, respectively. We have recognized $27, $25 and ($1,157) of interest expense related to uncertain tax positions for the years ended December 31,

2012, 2011 and 2010, respectively. We have not recognized any penalties in connection with our uncertain tax positions. The liabilities for unrecognized tax

benefits and accrued interest payable are components of other current liabilities on our balance sheet.

The tax years 2008 through 2011 remain subject to examination by major tax jurisdictions.

NOTE 11 — LONG-TERM DEBT:

Long-term debt consisted of the following:

 As of December 31,

 2012 2011

6 / % Senior Subordinated Notes due 2014 $ — $ 200,000 

8 / % Senior Notes due 2017 375,000 375,000 

1 / % Senior Convertible Notes due 2017 239,126 — 

7 / % Senior Notes due 2022 300,000 — 

Bank debt — 45,000 

Total long-term debt $914,126 $620,000 

Bank Debt

On April 26, 2011, we entered into an amended and restated revolving credit facility with commitments totaling $700,000 (subject to borrowing base

limitations) through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. On October 22, 2012, the

bank group reaffirmed our existing borrowing base at $400,000. As of December 31, 2012 and February 21, 2013, we had no outstanding borrowings under

our bank credit facility and letters of credit totaling $20,954 had been issued pursuant to the facility, leaving $379,046 of availability under the facility.

The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders taking into consideration the

estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries 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 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 five equal monthly installments.

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Our bank credit facility is guaranteed by our only subsidiary, Stone Offshore. Our 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 gas reserves representing at least

80% of the discounted present value of the future net cash flows from their oil and gas reserves reviewed in determining the borrowing base. At Stone’s option,

loans under our bank credit facility will bear interest at a rate based on the adjusted London Interbank Offering Rate plus an applicable margin, or a rate based

on the prime rate or federal funds rate plus an applicable margin.

Under the financial covenants of our bank credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the

credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) 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 3.0 to 1. As of December 31, 2012, our debt to

EBITDA Ratio was 1.55 to 1 and our EBITDA to consolidated Net Interest Expense Ratio was approximately 21.56 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 ownership 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.

Senior Convertible Notes

On March 6, 2012, we issued in a private offering $300,000 in aggregate principal amount of 1 / % Senior Convertible Notes due 2017 to qualified

institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes 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

sale of the 2017 Convertible Notes were approximately $291,145, after deducting fees and expenses. The 2017 Convertible Notes rank equally in right of

payment with all of our existing and future senior unsecured indebtedness. The 2017 Convertible Notes are effectively subordinated to our secured

indebtedness to the extent of the value of the related collateral. The 2017 Convertible Notes bear interest at a rate of 1.75% per year, payable on March 1 and

September 1 of each year, beginning on September 1, 2012. The 2017 Convertible Notes mature on March 1, 2017, unless earlier converted or repurchased.

We may not redeem the 2017 Convertible Notes at our option prior to the maturity date.

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, 2012, our closing share price was $20.52. 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 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.

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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.

If we undergo a fundamental change (as defined in the indenture related to the 2017 Convertible Notes) prior to maturity, holders of the 2017 Convertible

Notes will have the right, at their option, to require us to repurchase for cash some or all of their 2017 Convertible Notes at a repurchase price equal to 100% of

the principal amount of the 2017 Convertible Notes being repurchased, plus accrued and unpaid interest (including additional interest, if any) to, but

excluding, the fundamental change repurchase date.

If holders elect to convert the 2017 Convertible Notes in connection with certain fundamental change transactions described in the indenture related to the

2017 Convertible Notes, we will increase the conversion rate by a number of additional shares determined by reference to the provisions contained in the

indenture related to the 2017 Convertible Notes based on the effective date of, and the price paid (or deemed paid) per share of our common stock in, such

make-whole fundamental change. If holders of our common stock receive only cash in connection with certain make-whole fundamental changes, the price

paid (or deemed paid) per share will be the cash amount paid per share. Otherwise, the price paid (or deemed paid) per share will be equal to the average of the

closing sale prices of our common stock on the five trading days prior to, but excluding, the effective date of such make-whole fundamental change.

In connection with the sale of the 2017 Convertible Notes, 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(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 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.

The Purchased Call Options and Sold Warrants are separate contracts entered into by Stone and each of the Dealers, are not part of the terms of the 2017

Convertible Notes and will not affect the holders’ rights under the 2017 Convertible Notes. The Purchased Call Options are expected generally to reduce the

potential dilution upon conversion of the 2017 Convertible Notes in the event that the market value per share of our common stock at the time of exercise is

greater than the strike price of the Purchased Call Options. The Sold Warrants could separately have a dilutive effect to the extent that the market value per

share of our common stock exceeds the applicable strike price of the Sold Warrants.

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The estimated liability and equity components of this offering were recorded in accordance with ASC 470-20. The initial carrying amount of the liability

component of $229,170 was determined by measuring the fair value of a similar liability that does not have an associated equity component. An effective

market interest rate of 7.51% was used in the fair value determination. The carrying amount of the equity component of $70,830 was determined by deducting

the fair value of the liability component from the initial proceeds from the 2017 Convertible Notes. Transaction costs of approximately $8,855 were allocated

to the liability and equity components in proportion to the allocation of proceeds and accounted for as debt issuance and equity issuance costs, respectively.

The cost of the convertible note hedge of $70,830 and proceeds from the warrant transaction of $40,170 were recorded as adjustments to equity. A summary of

the entries to record the proceeds from the 2017 Convertible Notes, the cost of the Purchased Call Options and the proceeds from the Sold Warrants is as

follows:

Cash $ 260,485 

Other assets (deferred financing costs) 6,764 

Long-term debt (229,170) 

Additional paid-in capital (38,079) 

As of December 31, 2012, the carrying amount of the liability component of the 2017 Convertible Notes was $239,126. During the year ended

December 31, 2012, we recorded $9,956 of interest cost for the amortization of the discount and $951 of interest cost for the amortization of deferred

financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2012, we recorded $4,302 of interest cost related to the contractual

interest coupon on the 2017 Convertible Notes. At December 31, 2012, $1,750 had been accrued in connection with the March 1, 2013 interest payment.

Senior Notes

On November 8, 2012, we completed the public offering of $300,000 aggregate principal amount of 7 / % Senior Notes due 2022, 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. The 2022 Notes rank equally in right of payment with all

of our existing and future senior debt, and rank senior in right of payment to all of our existing and future subordinated debt. The 2022 Notes mature on

November 15, 2022, and interest is payable on the 2022 Notes on each May 15 and November 15, commencing on May 15, 2013. 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, 2012,

$3,313 had been accrued in connection with the May 15, 2013 interest payment.

On January 26, 2010, we completed a public offering of $275,000 aggregate principal amount of 8 / % Senior Notes due 2017, 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 $265,299. On November 17, 2010, we completed a public offering

of an additional $100,000 aggregate principal amount of our 2017 Notes. The net proceeds from this offering after deducting underwriting discounts,

commissions, fees and expenses totaled approximately $98,227. The 2017 Notes rank equally in right of payment with all of our existing and future senior

debt, and rank senior in right of payment to all of our existing and future subordinated debt. The 2017 Notes mature on February 1, 2017, and interest is

payable on each February 1 and August 1, commencing on August 1, 2010. We may, at our option, redeem all or part of the 2017 Notes at any time prior to

February 1, 2014 at a make-whole redemption price, and at any time on or after February 1, 2014 at fixed redemption prices. In addition, prior to February 1,

2013, we may, at our option, redeem up to 35% of the 2017 Notes with the cash proceeds of certain equity offerings. The 2017 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 2017 Notes a right to accelerate payment. At December 31,

2012, $13,477 had been accrued in connection with the February 1, 2013 interest payment.

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Senior Subordinated Notes

On December 15, 2004, we issued $200,000 6 / % Senior Subordinated Notes due 2014. In November 2012, we used proceeds from the 2022 Notes

offering to purchase a portion of our 2014 Notes pursuant to a tender offer and consent solicitation. In December 2012, the remaining 2014 Notes were

redeemed in full. The total cost of the redemption was $204,355, which included $200,681 to redeem the notes plus accrued and unpaid interest of $3,674.

The transaction resulted in a charge to earnings of $1,972 in 2012.

On December 5, 2001, we issued $200,000 8 / % Senior Subordinated Notes due 2011 (the “2011 Notes”). In January 2010, we used the proceeds from

the 2017 Notes offering to purchase our 2011 Notes pursuant to a tender offer and consent solicitation. In February 2010, the remaining 2011 Notes were

redeemed in full. The total cost of the redemption was $202,382, which included $200,483 to redeem the notes plus accrued and unpaid interest of $1,899.

The transaction resulted in a charge to earnings of $1,820 in 2010.

Deferred Financing Cost and Interest Cost

Other assets at December 31, 2012 and 2011 included approximately $27,753 and $14,437, respectively, of deferred financing costs, net of

accumulated amortization. These costs at December 31, 2012 related primarily to the issuance of the 2017 Convertible Notes, the 2022 Notes, the 2017 Notes

and our bank credit facility. The costs associated with the 2017 Convertible Notes, the 2022 Notes and the 2017 Notes are being amortized over the life of the

notes using a method that applies effective interest rates of 7.51%, 7.75% and 8.08%, respectively. The costs associated with our bank credit facility are being

amortized over the term of the facility.

Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2012, 2011 and 2010 was $68,031, $51,322 and

$42,975 respectively.

NOTE 12 — STOCK-BASED COMPENSATION:

We record stock compensation expense under U.S. GAAP for stock options and other equity-based compensation awards based on the fair value on the

date of grant. Compensation expense for equity-based compensation awards is recognized in our financial statements over the vesting period of the award.

For the year ended December 31, 2012, we incurred $13,399 of stock based compensation, of which $13,308 related to restricted stock issuances, $91

related to stock option grants and of which a total of approximately $4,288 was capitalized into oil and gas properties. For the year ended December 31, 2011,

we incurred $8,914 of stock based compensation, of which $8,796 related to restricted stock issuances, $118 related to stock option grants and of which a

total of approximately $3,010 was capitalized into oil and gas properties. For the year ended December 31, 2010, we incurred $8,462 of stock based

compensation, of which $8,263 related to restricted stock issuances, $199 related to stock option grants and of which a total of approximately $2,775 was

capitalized into oil and gas properties. Because of the non-cash nature of stock based compensation, the expensed portion of stock 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.

Under the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (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 the common stock on the date of grant and may not be re-priced without

stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock

options issued to non-employee directors vest ratably over a three-year service-vesting period and expire 10 years 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.

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Stock Options. There were no stock option grants during the years ended December 31, 2012, 2011 or 2010.

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 

Exercise prices for stock options outstanding at December 31, 2012 range from $6.97 to $53.20.

A summary of stock option activity under the 2009 Plan during the year ended December 31, 2011 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 484,694 $ 39.43 

Granted — — 

Exercised — — 

Forfeited (13,300) 37.98 

Expired (33,000) 48.85 

Options outstanding, end of period 438,394 38.76 3.6 years $ 1,143 

Options exercisable, end of period 378,710 41.66 3.1 years 457 

Options unvested, end of period

 59,684 20.36 

6.1

years 686 

A summary of stock option activity under the 2009 Plan during the year ended December 31, 2010 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 495,283 $39.61 

Granted — — 

Exercised — — 

Forfeited (6,190) 40.85 

Expired (4,399) 57.76 

Options outstanding, end of period 484,694 39.43 3.8 years $ 880 

Options exercisable, end of period 396,115 43.21 3.4 years 176 

Options unvested, end of period

 88,579 22.50 

6.9

years 704 

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, 2012, we issued 670,818 shares of restricted stock valued at $21,085. During the year ended December 31, 2011, we

issued 597,062 shares of restricted stock valued at $14,100. During the year ended December 31, 2010, we issued 395,869 shares of restricted stock valued

at $6,251.

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A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2012, 2011 and 2010 is as follows (amounts in table

represent actual values):

 2012 2011 2010

 

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 923,740 $ 20.08 783,606 $ 17.24 751,437 $ 20.68 

Issuances 670,818 31.43 597,062 23.62 395,869 15.79 

Lapse of restrictions (462,141) 18.29 (419,543) 19.91 (343,657) 23.09 

Forfeitures (23,543) 26.10 (37,385) 18.92 (20,043) 18.07 

Restricted stock outstanding, end of period 1,108,874 $27.56 923,740 $ 20.08 783,606 $ 17.24 

As of December 31, 2012, there was $18,547 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 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 $814, $735 and ($2) in 2012, 2011 and 2010, respectively.

NOTE 13 — 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, 2012, 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, 2012, 2011 and 2010.

NOTE 14 — COMMITMENTS AND CONTINGENCIES:

Lease Commitments

We lease office facilities in Lafayette and New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia under the terms of long-term, noncancelable leases expiring on various dates through 2018. 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, 2012

were as follows:

2013 $612 

2014 540 

2015 540 

2016 260 

2017 203 

2018 82 

Payments related to our lease obligations for the years ended December 31, 2012, 2011 and 2010 were approximately $894, $446 and $703,

respectively.

Other Commitments

We are contingently liable to surety insurance companies in the amount of $90,789 relative to bonds issued on our behalf to the Bureau of Ocean

Energy Management (“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.

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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 $52,299 to be incurred over the next three years.

The Oil Pollution Act (“OPA”) imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of

financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA and a final

rule adopted by the BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must

demonstrate financial responsibility in amounts ranging from at least $10,000 in specified state waters to at least $35,000 in Outer Continental Shelf (“OCS”)

waters, with higher amounts of up to $150,000 in certain limited circumstances where the BOEM believes such a level is justified by the risks posed by the

operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the BOEM’s

final rule. 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 also named as a defendant in certain lawsuits and are a party to certain 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.

We have been served with several petitions filed by the Louisiana Department of Revenue (“LDR”) in Louisiana state court claiming additional franchise

taxes due. In addition, we have received preliminary assessments from the LDR for additional franchise taxes resulting from audits of Stone and other

subsidiaries. These assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties located on the OCS, which are

transported through the State of Louisiana, should be sourced to the State of Louisiana for purposes of computing the Louisiana franchise tax apportionment

ratio. We disagree with these contentions and are defending ourselves against these claims. Total asserted claims plus estimated accrued interest amount to

approximately $29,581. The franchise tax years 2010, 2011 and 2012 for Stone remain subject to examination, which potentially exposes us to additional

estimated assessments of $2,440 including accrued interest. We estimate the potential range of loss upon resolution of this matter to be between $0 and

$32,021.

NOTE 15 — 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, 2012, the liability for such vested benefits was approximately

$1,059 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

$8,113, $11,600, and $5,888, net of amounts capitalized, for each of the years ended December 31, 2012, 2011 and 2010, 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 increases the number of shares of common stock that Stone may issue under the 2009 Plan, and the number of shares of 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 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 and restricted stock awards or any combination as is best suited to the circumstances of the particular

employee or nonemployee director. 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 the board of directors. Under the 2009 Plan, we may grant

both incentive stock options qualifying under Section 422

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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 the common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to

all employees vest ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock options issued to non-employee directors vest

ratably over a three-year service-vesting period and expire 10 years subsequent to award. In addition, the 2009 Plan provides that shares available under the

2009 Plan may be granted as restricted stock. Restricted stock grants typically vest in one to three years at the discretion of the Compensation Committee of the

board of directors. At December 31, 2012, we had approximately 2,684,466 additional shares available for issuance pursuant to the 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, 2012, 2011 and 2010, Stone contributed $1,759, $1,435 and $1,301, 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

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 the

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, 2012 and 2011, plan assets of $7,498 and $6,410,

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. Executives

who are terminated within the scope of the Executive Plan will be entitled to certain payments and benefits including the following: a base salary up to the date

of termination; in the case of the CEO and CFO, a lump sum severance payment of 2.99 times the sum of his annual pay and any target bonus at the one

hundred percent level; 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; 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; 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;

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,” they will be reduced as necessary to avoid the 20% excise tax under Section 4999 of the Internal Revenue Code of 1986, as amended (the

“Code”), but only if the executive is in a better net after-tax position after such reduction. Also, if a payment would be to a “key employee” for purposes of

Section 409A of the Code, payment will be delayed until six months after his termination if required to comply with Section 409A. Benefits paid upon a

change of control, without regard to whether there is a termination of employment, include the following: lapse of restrictions on restricted stock, accelerated

vesting and cash-out of all in-the-money stock options, a 401(k) plan employer matching contribution at the rate of 50%, and 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 Internal Revenue Code and to provide

that said plan will remain in force and effect unless and until terminated by the 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: 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; continued health plan

coverage for six months; and 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: lapse of restrictions on restricted stock, accelerated vesting and cash-out

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of all in-the-money stock options, a 401(k) plan employer matching contribution at the rate of 50%, and a lump sum cash payment equal to the product of

(i) 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 timevested portion of his long-term stock incentive award, if any, for the calendar year in which the change of control occurs times (ii) 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 16 — OIL AND GAS RESERVE INFORMATION — UNAUDITED:

Our estimated net proved oil and gas reserves at December 31, 2012 have been prepared in accordance with guidelines established by the Securities and

Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective

dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of

development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values

should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

The following table sets forth an analysis of the estimated quantities of net proved and proved developed 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, 2012, 2011 and 2010 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a 12-month

average pricing assumption. In the first quarter of 2012, we began reporting NGL volumes and revenues separately from gas volumes. Historically, we

reported “wet” gas volumes, which included entrained liquids. We now report NGLs and “dry” gas (shrunk for removal of liquids) volumes. Reserve volumes

for the year ended December 31, 2011 have been reclassified to conform to the current presentation. Reserve volumes for the years ended December 31, 2010

and 2009 have not been reclassified to conform to the current presentation given the immateriality of NGL volumes in such periods.

 

Oil

(MBbls)

NGLs

(MBbls)

Natural

Gas

(MMcf)

Oil,

Natural

Gas and

NGLs

(MMcfe)

Estimated proved reserves as of December 31, 2009 32,336 — 216,694 410,711 

Revisions of previous estimates 3,299 574 12,670 35,906 

Extensions, discoveries and other additions 2,668 — 82,846 98,854 

Purchase of producing properties 637 — 3,816 7,637 

Sale of reserves (23) — (153) (289) 

Production (5,714) (574) (41,168) (78,896) 

Estimated proved reserves as of December 31, 2010 33,203 — 274,705 473,923 

Revisions of previous estimates 2,889 4,911 (26,725) 20,075 

Extensions, discoveries and other additions 3,544 — 93,520 114,784 

Purchase of producing properties 14,396 — 24,595 110,971 

Sale of reserves (1,950) — (2,150) (13,850) 

Production (6,427) (506) (38,466) (80,064) 

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 

Estimated proved developed reserves: 

as of December 31, 2010 25,000 — 174,876 324,876 

as of December 31, 2011 30,914 3,195 171,871 376,528 

as of December 31, 2012 29,005 8,593 210,956 436,540 

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

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.

Year Ended December 31, 2011. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (94 Bcfe),

our deep gas development project at LaPosada (11 Bcfe) and our GOM drilling program at Mississippi Canyon Block 109 (6 Bcfe). Purchase of producing

properties primarily relates to our acquisition of the Pompano and Mica fields (102 Bcfe) and our acquisition of an additional 15% working interest in the

Pyrenees project (6 Bcfe). Sale of reserves primarily relates to the sale of our non-operated interest in the Main Pass Block 296 and 311 fields (13 Bcfe).

Year Ended December 31, 2010. Revisions of previous estimates were the result of positive reserve report pricing changes extending the economic limits

of reservoirs (28 Bcfe) and well performance (5 Bcfe). Extensions, discoveries and other additions were primarily the result of our Appalachia drilling

program (77 Bcfe) and our GOM drilling program primarily at Mississippi Canyon Block 109 (18 Bcfe).

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, 2012. 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 preceding 12-months’ average price based on closing prices on the

first day of each month, or prices defined by existing contractual arrangements. The 2012 average 12-month oil and gas prices net of differentials were

$101.20 per Bbl of oil, $38.23 per Bbl of NGLs and $2.68 per Mcf of gas. The 2011 average 12-month oil and gas prices net of differentials were $100.97

per Bbl of oil, $58.26 per Bbl of NGLs and $4.74 per Mcf of gas. The 2010 average 12-month oil and gas prices net of differentials were $77.68 per Bbl of

oil and $4.46 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,

 2012 2011 2010

Future cash inflows $6,295,455 $6,171,279 $ 3,803,004 

Future production costs (1,946,426) (1,747,806) (1,191,718) 

Future development costs (1,241,531) (1,219,214) (907,956) 

Future income taxes (799,007) (852,364) (330,651) 

Future net cash flows 2,308,491 2,351,895 1,372,679 

10% annual discount (794,632) (808,933) (415,050) 

Standardized measure of discounted future net cash flows $ 1,513,859 $1,542,962 $ 957,629 

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Changes in Standardized Measure

Year Ended December 31,

 2012 2011 2010

Standardized measure at beginning of year $1,542,962 $ 957,629 $ 614,987 

Sales and transfers of oil, gas and NGLs produced, net of production

costs (697,741) (670,347) (487,418) 

Changes in price, net of future production costs (380,841) 502,324 485,272 

Extensions and discoveries, net of future production and development

costs 178,272 293,168 270,629 

Changes in estimated future development costs, net of development

costs incurred during the period 212,329 97,852 119,986 

Revisions of quantity estimates 76,450 (27,854) 147,509 

Accretion of discount 207,292 118,722 64,836 

Net change in income taxes 22,947 (300,363) (196,219) 

Purchases of reserves in-place 276,389 567,286 21,264 

Sales of reserves in-place 2,480 (36,278) 1,424 

Changes in production rates due to timing and other 73,320 40,823 (84,641) 

Net increase (decrease) in standardized measure (29,103) 585,333 342,642 

Standardized measure at end of year $1,513,859 $1,542,962 $ 957,629 

NOTE 17 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION — UNAUDITED:

The results of operations by quarter are as follows:

 2012 Quarter Ended

 March 31 June 30 September 30 December 31

Operating revenue $244,957 $226,561 $227,397 $254,871 

Income from operations 84,927 56,156 44,485 78,397 

Net income 50,974 30,547 23,659 44,246 

Basic earnings per share $ 1.03 $ 0.62 $ 0.48 $ 0.89 

Diluted earnings per share $ 1.03 $ 0.62 $ 0.48 $ 0.89 

 2011 Quarter Ended

 March 31 June 30 September 30 December 31

Operating revenue $200,039 $235,734 $214,594 $223,616 

Income from operations 64,752 92,155 80,694 73,399 

Net income 39,792 57,196 51,821 45,523 

Basic earnings per share $ 0.81 $ 1.17 $ 1.06 $ 0.93 

Diluted earnings per share $ 0.81 $ 1.17 $ 1.06 $ 0.93 

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NOTE 18 — GUARANTOR FINANCIAL STATEMENTS:

Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of our 2017 Notes, 2017 Convertible Notes and 2022 Notes. Our other

subsidiary (the “Non-Guarantor Subsidiary”) did not provide a guarantee. Our non-guarantor subsidiary, Caillou Boca, was merged into Stone Offshore on

September 6, 2012. The following presents consolidating financial information as of December 31, 2012 and 2011 and for the years ended December 31,

2012, 2011 and 2010 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiary, and consolidated basis. Elimination entries presented

are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2012

(In thousands of dollars)

 Parent

Guarantor

Subsidiary

NonGuarantor

Subsidiary Eliminations Consolidated

Assets 

Current assets: 

Cash and cash equivalents $ 228,398 $ 51,128 $ — $ — $ 279,526 

Accounts receivable 59,213 108,075 — — 167,288 

Fair value of hedging contracts — 39,655 — — 39,655 

Current income tax receivable 10,027 — — — 10,027 

Deferred taxes * 5,947 9,567 — — 15,514 

Inventory 3,924 283 — — 4,207 

Other current assets 3,626 — — — 3,626 

Total current assets 311,135 208,708 — — 519,843 

Oil and gas properties, full cost method: 

Proved, net 634,697 1,099,603 — — 1,734,300 

Unevaluated 254,757 193,038 — — 447,795 

Other property and equipment, net 22,115 — — — 22,115 

Fair value of hedging contracts — 9,199 — — 9,199 

Other assets, net 41,679 1,500 — — 43,179 

Investment in subsidiary 736,331 — — (736,331) — 

Total assets $ 2,000,714 $ 1,512,048 $ — ($ 736,331) $2,776,431 

Liabilities and Stockholders’ Equity 

Current liabilities: 

Accounts payable to vendors $ 74,503 $ 19,858 $ — $ — $ 94,361 

Undistributed oil and gas proceeds 21,841 1,573 — — 23,414 

Accrued interest 18,546 — — — 18,546 

Fair value of hedging contracts — 149 — — 149 

Asset retirement obligations — 66,260 — — 66,260 

Other current liabilities 16,765 — — — 16,765 

Total current liabilities 131,655 87,840 — — 219,495 

Long-term debt 914,126 — — — 914,126 

Deferred taxes * 47,758 263,072 — — 310,830 

Asset retirement obligations 5,479 416,563 — — 422,042 

Fair value of hedging contracts — 1,530 — — 1,530 

Other long-term liabilities 29,563 6,712 — — 36,275 

Total liabilities 1,128,581 775,717 — — 1,904,298 

Commitments and contingencies 

Stockholders’ equity: 

Common stock 484 — — — 484 

Treasury stock (860) — — — (860) 

Additional paid-in capital 1,386,475 1,496,510 — (1,496,510) 1,386,475 

Accumulated earnings (deficit) (542,799) (789,012) — 789,012 (542,799) 

Accumulated other comprehensive income (loss) 28,833 28,833 — (28,833) 28,833 

Total stockholders’ equity 872,133 736,331 — (736,331) 872,133 

Total liabilities and stockholders’ equity $ 2,000,714 $ 1,512,048 $ — ($ 736,331) $2,776,431 

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

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CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2011

(In thousands of dollars)

 Parent

Guarantor

Subsidiary

NonGuarantor

Subsidiary Eliminations Consolidated

Assets 

Current assets: 

Cash and cash equivalents $ 37,389 $ 926 $ 136 $ — $ 38,451 

Accounts receivable 36,463 81,452 1,353 (1,129) 118,139 

Fair value of hedging contracts — 25,177 — — 25,177 

Current income tax receivable 19,946 — — — 19,946 

Deferred taxes * 8,269 17,803 — — 26,072 

Inventory 4,360 283 — — 4,643 

Other current assets 791 — — — 791 

Total current assets 107,218 125,641 1,489 (1,129) 233,219 

Oil and gas properties, full cost method: 

Proved, net 387,554 1,083,192 2,693 — 1,473,439 

Unevaluated 246,269 155,340 — — 401,609 

Other property and equipment, net 11,172 — — — 11,172 

Fair value of hedging contracts — 22,543 — — 22,543 

Other assets, net 20,873 2,896 — — 23,769 

Investment in subsidiary 733,533 (273) — (733,260) — 

Total assets $1,506,619 $ 1,389,339 $ 4,182 ($ 734,389) $2,165,751 

Liabilities and Stockholders’ Equity 

Current liabilities: 

Accounts payable to vendors $ 78,170 $ 25,866 $ 39 ($ 1,129) $ 102,946 

Undistributed oil and gas proceeds 26,036 1,292 — — 27,328 

Accrued interest 14,059 — — — 14,059 

Fair value of hedging contracts — 11,122 — — 11,122 

Asset retirement obligations — 62,676 — — 62,676 

Other current liabilities 22,974 5,396 — — 28,370 

Total current liabilities 141,239 106,352 39 (1,129) 246,501 

Long-term debt 620,000 — — — 620,000 

Deferred taxes * 56,970 190,865 — — 247,835 

Asset retirement obligations 7,626 351,061 4,416 — 363,103 

Fair value of hedging contracts — 815 — — 815 

Other long-term liabilities 12,955 6,713 — — 19,668 

Total liabilities 838,790 655,806 4,455 (1,129) 1,497,922 

Commitments and contingencies 

Stockholders’ equity: 

Common stock 481 — — — 481 

Treasury stock (860) — — — (860) 

Additional paid-in capital 1,338,565 1,724,232 1,639 (1,725,871) 1,338,565 

Accumulated earnings (deficit) (692,225) (1,012,567) (1,912) 1,014,479 (692,225) 

Accumulated other comprehensive income (loss) 21,868 21,868 — (21,868) 21,868 

Total stockholders’ equity 667,829 733,533 (273) (733,260) 667,829 

Total liabilities and stockholders’ equity $1,506,619 $ 1,389,339 $ 4,182 ($ 734,389) $2,165,751 

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

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2012

(In thousands of dollars)

 Parent

Guarantor

Subsidiary

NonGuarantor

Subsidiary Eliminations Consolidated

Operating revenue: 

Oil production $ 26,149 $735,155 $ — $ — $ 761,304 

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 

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2011

(In thousands of dollars)

 Parent

Guarantor

Subsidiary

NonGuarantor

Subsidiary Eliminations Consolidated

Operating revenue: 

Oil production $ 5,675 $658,283 $ — $ — $663,958 

Gas production 19,470 151,141 — — 170,611 

Natural gas liquids production — 29,996 — — 29,996 

Other operational income 3,085 249 604 — 3,938 

Derivative income, net — 1,418 — — 1,418 

Total operating revenue 28,230 841,087 604 — 869,921 

Operating expenses: 

Lease operating expenses 6,632 169,018 231 — 175,881 

Transportation, processing and gathering expenses — 8,958 — — 8,958 

Production taxes 1,434 7,946 — — 9,380 

Depreciation, depletion, amortization 17,860 261,326 834 — 280,020 

Accretion expense 15 30,385 364 — 30,764 

Salaries, general and administrative 40,073 94 2 — 40,169 

Incentive compensation expense 11,600 — — — 11,600 

Other operational expenses 1,404 745 — — 2,149 

Total operating expenses 79,018 478,472 1,431 — 558,921 

Income (loss) from operations (50,788) 362,615 (827) — 311,000 

Other (income) expenses: 

Interest expense 9,043 246 — — 9,289 

Interest income (178) (242) — — (420) 

Other (income) expense, net (52) (1,890) — — (1,942) 

Loss on early extinguishment of debt 607 — — — 607 

(Income) loss from investment in subsidiaries (232,751) 827 — 231,924 — 

Total other (income) expenses (223,331) (1,059) — 231,924 7,534 

Income (loss) before taxes 172,543 363,674 (827) (231,924) 303,466 

Provision (benefit) for income taxes: 

Current (20,386) — — — (20,386) 

Deferred (1,403) 130,923 — — 129,520 

Total income taxes (21,789) 130,923 — — 109,134 

Net income (loss) $ 194,332 $ 232,751 ($ 827) ($ 231,924) $ 194,332 

Comprehensive income (loss) $ 230,404 $ 232,751 ($ 827) ($ 231,924) $ 230,404 

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2010

(In thousands of dollars)

 Parent

Guarantor

Subsidiary

NonGuarantor

Subsidiary Eliminations Consolidated

Operating revenue: 

Oil production $ 51,357 $366,591 $ — $ — $ 417,948 

Gas production 61,137 149,549 — — 210,686 

Natural gas liquids production — 27,473 — — 27,473 

Other operational income 4,831 (54) 1,139 — 5,916 

Derivative income, net 3,265 — — — 3,265 

Total operating revenue 120,590 543,559 1,139 — 665,288 

Operating expenses: 

Lease operating expenses 64,868 85,344 — — 150,212 

Transportation, processing and gathering expenses — 7,218 — — 7,218 

Production taxes 3,631 2,177 — — 5,808 

Depreciation, depletion, amortization 40,351 206,856 994 — 248,201 

Accretion expense 14,503 19,524 442 — 34,469 

Salaries, general and administrative 42,741 17 1 — 42,759 

Incentive compensation expense 5,888 — — — 5,888 

Other operational expenses 2,097 3,482 — — 5,579 

Total operating expenses 174,079 324,618 1,437 — 500,134 

Income (loss) from operations (53,489) 218,941 (298) — 165,154 

Other (income) expenses: 

Interest expense 12,192 — — — 12,192 

Interest income (1,439) (25) — — (1,464) 

Other income (53) (762) 39 — (776) 

Other expense 601 70 — — 671 

Loss on early extinguishment of debt 1,820 — — — 1,820 

(Income) loss from investment in subsidiary (140,366) 337 — 140,029 — 

Total other (income) expenses (127,245) (380) 39 140,029 12,443 

Income (loss) before taxes 73,756 219,321 (337) (140,029) 152,711 

Provision (benefit) for income taxes: 

Current 5,896 (88) — — 5,808 

Deferred (28,569) 79,043 — — 50,474 

Total income taxes (22,673) 78,955 — — 56,282 

Net income (loss) $ 96,429 $ 140,366 ($ 337) ($ 140,029) $ 96,429 

Comprehensive income (loss) $ 97,605 $ 140,366 ($ 337) ($ 140,029) $ 97,605 

F-36
Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2012

(In thousands of dollars)

 Parent

Guarantor

Subsidiary

NonGuarantor

Subsidiary 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-37
Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2011

(In thousands of dollars)

 Parent

Guarantor

Subsidiary

NonGuarantor

Subsidiary Eliminations Consolidated

Cash flows from operating activities: 

Net income (loss) $ 194,332 $ 232,751 ($ 827) ($231,924) $ 194,332 

Adjustments to reconcile net income (loss) to net cash provided by

operating activities: 

Depreciation, depletion and amortization 17,860 261,326 834 — 280,020 

Accretion expense 15 30,385 364 — 30,764 

Deferred income tax provision (benefit) (1,403) 130,923 — — 129,520 

Settlement of asset retirement obligations — (63,391) — — (63,391) 

Non-cash stock compensation expense 5,905 — — — 5,905 

Excess tax benefits (1,493) — — — (1,493) 

Non-cash derivative income — (2,216) — — (2,216) 

Loss on early extinguishment of debt 607 — — — 607 

Non-cash interest expense 1,908 — — — 1,908 

Other non-cash income (1,602) — — — (1,602) 

Non-cash (income) loss from investment in subsidiaries (230,861) (1,063) — 231,924 — 

Change in current income taxes (19,451) — — — (19,451) 

Change in intercompany receivables/payables 217,287 (217,724) 437 — — 

Increase in accounts receivable (11,022) (7,688) (890) — (19,600) 

(Increase) decrease in other current assets (80) 14 — — (66) 

Decrease in inventory 1,605 14 — — 1,619 

Increase in accounts payable 2,658 3,341 40 — 6,039 

Increase in other current liabilities 23,440 6,143 — — 29,583 

Other (1,628) — — — (1,628) 

Net cash provided by (used in) operating activities 198,077 372,815 (42) — 570,850 

Cash flows from investing activities: 

Investment in oil and gas properties (309,026) (455,903) (4) — (764,933) 

Proceeds from sale of oil and gas properties, net of expenses 5,575 82,355 — — 87,930 

Investment in fixed and other assets (2,247) — — — (2,247) 

Net cash used in investing activities (305,698) (373,548) (4) — (679,250) 

Cash flows from financing activities: 

Proceeds from bank borrowings 75,000 — — — 75,000 

Repayment of bank borrowings (30,000) — — — (30,000) 

Deferred financing costs (4,017) — — — (4,017) 

Excess tax benefits 1,493 — — — 1,493 

Net payments for share based compensation (2,581) — — — (2,581) 

Net cash provided by financing activities 39,895 — — — 39,895 

Net change in cash and cash equivalents (67,726) (733) (46) — (68,505) 

Cash and cash equivalents, beginning of period 105,115 1,659 182 — 106,956 

Cash and cash equivalents, end of period $ 37,389 $ 926 $ 136 $ — $ 38,451 

F-38
Table of Contents

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2010

(In thousands of dollars)

 Parent

Guarantor

Subsidiary

NonGuarantor

Subsidiary Eliminations Consolidated

Cash flows from operating activities: 

Net income (loss) $ 96,429 $ 140,366 ($ 337) ($140,029) $ 96,429 

Adjustments to reconcile net income (loss) to net cash provided by

operating activities: 

Depreciation, depletion and amortization 40,351 206,856 994 — 248,201 

Accretion expense 14,503 19,524 442 — 34,469 

Deferred income tax provision (benefit) (28,569) 79,043 — — 50,474 

Settlement of asset retirement obligations (6,461) (30,440) — — (36,901) 

Non-cash stock compensation expense 5,692 — — — 5,692 

Excess tax benefits (299) — — — (299) 

Non-cash derivative income (324) — — — (324) 

Loss on early extinguishment of debt 1,820 — — — 1,820 

Non-cash interest expense 858 — — — 858 

Other non-cash expense 979 — — — 979 

Non-cash (income) loss from investment in subsidiary (140,366) 337 — 140,029 — 

Change in current income taxes (10,783) (88) — — (10,871) 

Change in intercompany receivable/payables 349,118 (347,941) (1,177) — — 

(Increase) decrease in accounts receivable (11,556) 61,254 (65) — 49,633 

Decrease in other current assets 18 5 6 — — 74 

Decrease in inventory 1,848 275 — — 2,123 

Increase (decrease) in accounts payable (1,045) 272 — — (773) 

Decrease in other current liabilities (17,423) (665) — — (18,088) 

Other expenses 1,230 68 — — 1,298 

Net cash provided by (used in) operating activities 296,020 128,917 (143) — 424,794 

Cash flows from investing activities: 

Investment in oil and gas properties (265,198) (136,394) (175) — (401,767) 

Proceeds from sale of oil and gas properties, net of expenses 25,455 6,180 — — 31,635 

Investment in fixed and other assets (2,949) — — — (2,949) 

Acquisition of non-controlling interest — (1,007) — — (1,007) 

Net cash used in investing activities (242,692) (131,221) (175) — (374,088) 

Cash flows from financing activities: 

Repayment of bank borrowings (175,000) — — — (175,000) 

Proceeds from issuance of senior notes 375,000 — — — 375,000 

Deferred financing costs (11,474) — — — (11,474) 

Redemption of senior subordinated notes (200,503) — — — (200,503) 

Excess tax benefits 299 — — — 299 

Net payments for share based compensation (1,365) — — — (1,365) 

Net cash used in financing activities (13,043) — — — (13,043) 

Net increase (decrease) in cash and cash equivalents 40,285 (2,304) (318) — 37,663 

Cash and cash equivalents, beginning of period 64,830 3,963 500 — 69,293 

Cash and cash equivalents, end of period $ 105,115 $ 1,659 $ 182 $ — $106,956 

F-39
Table of Contents

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 new 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 new rule.

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

Bcf. One billion cubic feet of gas.

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

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

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

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

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or

stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local

geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.

The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of

basins, trends, provinces, plays, areas-of-interest, etc.

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

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

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

Mcf. One thousand cubic feet of gas.

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

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

MMBtu. One million Btus.

MMcf. One million cubic feet of gas.

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

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

numbers.

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

rights to explore the property.

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

production exceeds production expenses and taxes.

Proved developed reserves. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in

which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction technology equipment and

infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

G-1
Table of Contents

Proved oil and natural gas reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with

reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating

methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is

reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must have

commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Reasonable certainty is defined as “much

more likely to be achieved than not”.

Proved undeveloped reserves. 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 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-dayof-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
Table of Contents

EXHIBIT INDEX

Exhibit

Number Description

 3.1

 

Certificate of Incorporation of the Registrant, as amended on June 4, 1993, February 1, 2001 and February 19, 2002 (incorporated by

reference to Exhibit 3.1 to the Registrant’s Quarterly Report on Form 10-Q filed August 7, 2012 (File No.001-12074)).

 3.2

 

Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit 3.1 to the

Registrant’s Current Report on Form 8-K filed May 21, 2008 (File No. 001-12074)).

 4.1

 

Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004

(incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed December 17, 2004 (File No. 001-12074)).

 4.2

 

First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank,

National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on

Form 8-K filed August 29, 2008 (File No. 001-12074)).

 4.3

 

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)).

 4.4

 

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)).

 4.5

 

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)).

 4.6

 

Indenture related to the 1 / % 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 / % 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)).

 4.7

 

Second Supplemental Indenture, dated as of November 6, 2012, to the Indenture, dated as of December 15, 2004, 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 8, 2012 (File No. 001-12074)).

 4.8

 

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)).

 †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)).

 3 4

 3 4
Table of Contents

 †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 Form 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

 

$700,000,000 Third 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 April 26, 2011 (incorporated by reference to

Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-12074)).

 10.14

 

Amendment No. 1 and Consent dated as of February 28, 2012 to the Third Amended and Restated Credit Agreement (incorporated by

reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 5, 2012 (File No. 001-12074)).

 10.15

 

Amendment No. 2 and Consent dated as of October 22, 2012 to the Third Amended and Restated Credit Agreement (incorporated by

reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed October 22, 2012 (File No. 001-12074)).
Table of Contents

 10.16

 

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)).

 10.17

 

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)).

 10.18

 

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)).

 10.19

 

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)).

 10.20

 

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)).

 10.21

 

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)).

 10.22

 

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)).

 10.23

 

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)).

 10.24

 

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)).

 10.25

 

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)).

 10.26

 

Amendment to Base Warrant Confirmation and Additional Warrant Confirmation dated March 5, 2012, by and between Stone Energy

Corporation and Bank of America N.A. (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K filed

March 6, 2012 (File No. 001-12074)).

 *21.1 Subsidiaries of the Registrant.

 *23.1 Consent of Independent Registered Public Accounting Firm.

 *23.2 Consent of Netherland, Sewell & Associates, Inc.

 *31.1

 

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

1934.

 *31.2

 

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

1934.
Table of Contents

 *#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 Schema Document

**101.CAL XBRL Calculation Linkbase Document

**101.DEF XBRL Definition Linkbase Document

**101.LAB XBRL Label Linkbase Document

**101.PRE XBRL Presentation Linkbase Document

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

* Filed or furnished herewith.

** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data

file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not

filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

# 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.
Exhibit 21.1

STONE ENERGY CORPORATION

SUBSIDIARIES AS OF DECEMBER 31, 2012

Stone Energy Offshore, L.L.C., a Delaware limited liability company
Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-3 No. 333-161391) of Stone Energy Corporation, and

(2) Registration Statement (Form S-3 No. 333-184532) of Stone Energy Corporation, and

(3) Registration Statement (Form S-8 No. 333-67332) pertaining to the Stone Energy Corporation 2001 Amended and Restated Stock Option Plan, and

(4) Registration Statement (Form S-8 No. 333-51968) pertaining to the Basin Exploration, Inc. Equity Incentive Plan, and

(5) Registration Statement (Form S-8 No. 333-64448) pertaining to the Stone Energy Corporation 2001 Amended and Restated Stock Option Plan, and

(6) Registration Statement (Form S-8 No. 333-87849) pertaining to the Stone Energy Corporation 2001 Amended and Restated Stock Option Plan, and

(7) Registration Statement (Form S-8 No. 333-107440) pertaining to the Stone Energy Corporation 2001 Amended and Restated Stock Option Plan, and

(8) Registration Statement (Form S-8 No. 333-160424) pertaining to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, and

(9) Registration Statement (Form S-8 No. 333-174992) pertaining to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan;

of our reports dated February 27, 2013, with respect to the consolidated financial statements of Stone Energy Corporation and the effectiveness of internal

control over financial reporting of Stone Energy Corporation included in this Annual Report (Form 10-K) of Stone Energy Corporation for the year ended

December 31, 2012.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 27, 2013
Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We do hereby consent to the use of our name in “Item 2. Properties” of the Annual Report on Form 10-K of Stone Energy Corporation (the “Company”)

for the year ended December 31, 2012 and to the incorporation by reference thereof into the Company’s previously filed Registration Statements on Form S-8

(Registration Nos. 33-67332, 333-51968, 333-64448, 333-87849, 333-107440, 333-160424 and 333-174992) and Form S-3 (Registration Nos. 333-161391 and

333-184532) and to the inclusion of our report dated January 24, 2013 in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

NETHERLAND, SEWELL & ASSOCIATES, INC.

By: /s/ Danny D. Simmons

Name:

 Danny D. Simmons, P.E.

Title: President and Chief Operating Officer

Houston, Texas

February 27, 2013
Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

I, David H. Welch, certify that:

1. I have reviewed this Annual Report on Form 10-K of Stone Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the

statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this

report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects

the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to

us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under

our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about

the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such

evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s

most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is

reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to

the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are

reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s

internal control over financial reporting.

February 27, 2013 /s/ David H. Welch

David H. Welch

President and Chief Executive Officer
Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

I, Kenneth H. Beer, certify that:

1. I have reviewed this Annual Report on Form 10-K of Stone Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the

statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this

report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects

the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to

us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under

our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about

the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such

evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s

most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is

reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to

the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are

reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s

internal control over financial reporting.

February 27, 2013 /s/ Kenneth H. Beer

Kenneth H. Beer

Executive Vice President and Chief Financial Officer
Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND

CHIEF FINANCIAL OFFICER

Pursuant to 18 U.S.C. § 1350 and in connection with the accompanying report on Form 10-K of Stone Energy Corporation (the “Company”) for the

year ended December 31, 2012 that is being filed concurrently with the Securities and Exchange Commission on the date hereof (the “Report”), each of the

undersigned officers of the Company hereby certifies, to the best of his knowledge, that:

(i.) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(ii.) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 27, 2013 /s/ David H. Welch

David H. Welch

President and Chief Executive Officer

/s/ Kenneth H. Beer

Kenneth H. Beer

Executive Vice President and Chief Financial Officer
Exhibit 99.1

January 24, 2013

Stone Energy Corporation

625 East Kaliste Saloom Road

Lafayette, Louisiana 70508

Ladies and Gentlemen:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2012, to the Stone Energy

Corporation (Stone) interest in certain oil and gas properties located in the United States. We completed our evaluation on or about the date of

this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Stone. The

estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange

Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification

Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for

Stone’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are

appropriate for such purpose.

We estimate the net reserves and future net revenue to the Stone interest in these properties, as of December 31, 2012, to be:

 Net Reserves Future Net Revenue (M$)

Category 

Oil

 (MBBL) 

NGL

 (MBBL) 

Gas

 (MMCF) Total 

 Present Worth 

at 10%

Proved Developed Producing 14,080.8 1,937.0 57,864.5 683,023.4 733,899.9 

Proved Developed Non-Producing 14,923.8 6,655.4 153,090.4 1,084.931.1 654,995.7 

Proved Undeveloped 15,913.1 9,474.9 184,417.8 1,339,544.6 631,972.2 

Total Proved 44,917.7 18,067.3 395,372.7 3,107,499.2 2,020,867.8 

Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels

(MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard

temperature and pressure bases.

The estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have

not been included. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for

which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves

subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not

been adjusted for risk.

Gross revenue is Stone’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after

deductions for Stone’s share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before

consideration of any income taxes. The ad valorem taxes include Stone’s share of the Pennsylvania unconventional gas impact fee. The

future net revenue has been
discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money.

Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of

the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the

period January through December 2012. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.21 per barrel is

adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average regional spot prices are

adjusted by lease for energy content, transportation fees, and local price differentials. The average adjusted product prices weighted by

production over the remaining lives of the properties are $101.19 per barrel of oil, $38.22 per barrel of NGL, and $2.680 per MCF of gas.

Operating costs used in this report are based on operating expense records of Stone. For nonoperated properties, these costs include the perwell overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and

field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Stone’s estimate of

the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs are held

constant throughout the lives of the properties.

Capital costs used in this report were provided by Stone and are based on authorizations for expenditure and actual costs from recent activity.

Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of

future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital

costs to be reasonable. Abandonment costs used in this report are Stone’s estimates of the costs to abandon the wells, platforms, and

production facilities, net of any salvage value. Capital costs and abandonment costs are held constant to the date of expenditure.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or

condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our

estimates do not include any costs due to such possible liability.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Stone

interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our

projections are based on Stone receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of

oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible;

probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.

Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual

reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions

including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be

operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest

owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are

recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental

policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such

reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data,

well test data, production data, historical price and cost information, and property
ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in

accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of

Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including

performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to

categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behindpipe zones, non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performancerelated estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with

analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties

inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional

judgment.

The data used in our estimates were obtained from Stone, public data sources, and the nonconfidential files of Netherland, Sewell &

Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. The titles to the properties have not been

examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for

preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set

forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an

interest in these properties nor are we employed on a contingent basis.

 Sincerely,

 NETHERLAND, SEWELL & ASSOCIATES, INC.

 Texas Registered Engineering Firm F-2699

 /s/ C.H. (Scott) Rees III

 By: 

 C.H. (Scott) Rees III, P.E.

 Chairman and Chief Executive Officer

 /s/ Richard B. Talley, Jr. /s/ Patrick L. Higgs

By: By: 

 Richard B. Talley, Jr. Patrick L. Higgs

 Texas P.E. 102425, Louisiana P.E. 36998 Texas P.G. 985

 Vice President Vice President

Date Signed: January 24, 2013 Date Signed: January 24, 2013

RBT:SRM

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital

document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters,

limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original

document shall control and supersede the digital document.
DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also

included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum

Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance

and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and

options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee,

brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir

conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the

reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used

to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of

interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of

interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a

viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its

natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and

pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter

(from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category 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 equipment and infrastructure operational at the time of the reserves estimate if the extraction is

by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of

the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be

recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market

conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in

existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with

relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7
DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and

storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and

facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific

development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to

the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of

platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds,

measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste

disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically

producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated

development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) 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.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue

that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be

determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative

production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are

considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic

test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs)

and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support

equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and

salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are

sometimes referred to as geological and geophysical or “G&G” costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for

title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is 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. Generally, an exploratory well is any well that is not a development well, an extension well, a

service well, or a stratigraphic test well as those items are defined in this section.

(14) Extensionwell. An extension well is a well drilled to extend the limits of a known reservoir.

Definitions - Page 2 of 7
DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(15) 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 which are separated vertically by intervening

impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields

may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to

identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural

states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing

the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs,

including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such

as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other

nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities

undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is

the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard

the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a

refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are

delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a

common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons

that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant

that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which

synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of

exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10%

probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves

estimates.

Definitions - Page 3 of 7
DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and

interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and

engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a

defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons

in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable

alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented,

including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a

reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than

formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant

believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be

assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the

proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO)

elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally

higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty

through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned

as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but

which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the

sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50%

probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or

interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does

not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than

the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of

the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that

could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible

outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable

operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related

equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes

called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment

and facilities.

Definitions - Page 4 of 7
DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve

transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas

producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as

appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not

production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are 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 the hydrocarbons must have commenced or the operator must be

reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it

and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH)

as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower

contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for

an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if

geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited

to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the

reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other

evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the

project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental

entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.

The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report,

determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless

prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities

will be recovered. If probabilistic methods are used, there should be at least a 90%

Definitions - Page 5 of 7
DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much

more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical),

engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to

increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been

field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being

evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically

producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be

a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering

oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those

reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from

a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas

may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the

following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity

participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those

reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be

combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which

reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the

year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual

arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in

developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming

continuation of existing economic conditions.If estimated development expenditures are significant, they shall be presented

separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with

consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas

reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax

credits and allowances relating to the entity’s proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income

tax expenses from future cash inflows.

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash

flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is

confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Definitions - Page 6 of 7
DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources

may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and

undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells

include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for

in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific

geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also

includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as

“exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably

certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of

economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating

that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote

locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore

often do justify longer time periods, this determination must always take into consideration all of the facts and

circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years

should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even

though development may extend past five years include, but are not limited to, the following:

• The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum

number of wells necessary to maintain the lease generally would not constitute significant development activities);

• The company’s historical record at completing development of comparable long-term projects;

• The amount of time in which the company has maintained the leases, or booked the reserves, without significant

development activities;

• The extent to which the company has followed a previously adopted development plan (for example, if a company has

changed its development plan several times without taking significant steps to implement any of those plans,

recognizing proved undeveloped reserves typically would not be appropriate); and

• The extent to which delays in development are caused by external factors related to the physical operating environment (for example,

restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example,

shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of

fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by

actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other

evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 7 of 7