Edgar Filing: W&T OFFSHORE INC

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

Form 10-K

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

¨	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 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)


Texas		72-1121985
(State of incorporation)		(IRS Employer Identification Number)

Nine Greenway Plaza, Suite 300 Houston, Texas		77046-0908
(Address of principal executive offices)		(Zip Code)

(713) 626-8525

(Registrant’s telephone number, including area code)

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 $0.00001		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

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

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. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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). Yes x 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 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.

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $529,519,000 based on the closing sale price of $15.30 per share as reported by the New York Stock Exchange on June 29, 2012.

The number of shares of the registrant’s common stock outstanding on February 25, 2013 was 75,249,630.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders, to be filed within 120 days of the end of the fiscal year covered by this report, are incorporated by reference into Part III of this Form 10-K.

W&T OFFSHORE, INC.

TABLE OF CONTENTS


		Page
PART I
Item 1.	Business		1
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		32
Item 2.	Properties		33
Item 3.	Legal Proceedings		46
	Executive Officers of the Registrant		47
Item 4.	Mine Safety Disclosures		48
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		49
Item 6.	Selected Financial Data		52
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		56
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		74
Item 8.	Financial Statements and Supplementary Data		75
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		127
Item 9A.	Controls and Procedures		127
Item 9B.	Other Information		127
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		128
Item 11.	Executive Compensation		128
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		128
Item 13.	Certain Relationships and Related Transactions, and Director Independence		128
Item 14.	Principal Accountant Fees and Services		128
PART IV
Item 15.	Exhibits and Financial Statement Schedules		129
Signatures			136
Index to Consolidated Financial Statements			75
Glossary of Oil and Natural Gas Terms			133

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors, and market risks are discussed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of this Annual Report on Form 10-K and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission (“SEC”). Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date made. We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law. Unless the context requires otherwise, references in this Annual Report on Form 10-K to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

PART I

Item 1.

Business

W&T Offshore, Inc. is an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties primarily in the Gulf of Mexico and Texas. W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in 1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983.

The Gulf of Mexico is an area where we have developed significant technical expertise and where high production rates associated with hydrocarbon deposits have historically provided us the best opportunity to achieve a rapid return on our invested capital. We have leveraged our historic experience in the conventional shelf (water depths of less than 500 feet) to develop higher impact capital projects in the Gulf of Mexico in both the deepwater (water depths in excess of 500 feet) and the deep shelf (well depths in excess of 15,000 feet and water depths of less than 500 feet). We have acquired rights to explore and develop new prospects and acquired existing oil and natural gas properties in both the deepwater and the deep shelf, while at the same time continuing our focus on the conventional shelf.

During 2011, we significantly increased our activity onshore from what was previously a relatively minor presence. In May 2011, we acquired various properties and leasehold interests in four counties in the Permian Basin of West Texas (as described below) in a single transaction and separately acquired other leasehold interests in another county in the Permian Basin. In East Texas, we acquired leasehold interests in 2011 and have been evaluating this area through selective exploration and development activities.

As of December 31, 2012, we have interests in offshore leases covering approximately 1.2 million gross acres (0.8 million net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama. Onshore, we have leasehold interests in approximately 0.2 million gross acres (0.2 million net acres), substantially all of which are in Texas. Approximately 54% of our total net offshore acreage is developed and approximately 11% of our total net onshore acreage is developed. Of the onshore leasehold acreage classified as undeveloped, a substantial portion could expire in 2013 but is expected to be extended by drilling two additional wells in 2013 and can be further extended by additional operations or production in future years.

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultant, our total proved reserves at December 31, 2012 were 117.5 million barrels of oil equivalent (“MMBoe”) or 705.1 billion cubic feet equivalent (“Bcfe”). Approximately 53% of our reserves were classified as proved developed producing, 21% as proved developed non-producing and 26% as proved undeveloped. Classified by product, our reserves at December 31, 2012 were 47% oil, 13% natural gas liquids (“NGLs”) and 40% natural gas. These percentages were determined using the energy-equivalent ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs. This energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ significantly. Our total proved reserves had an estimated present value of future net revenues discounted at 10% (“PV-10”) of $2.8 billion. Our PV-10 after considering future cash outflows related to asset retirement obligations (“ARO”) and without deducting future income taxes was $2.5 billion, and our standardized measure of discounted future cash flows was $1.8 billion as of December 31, 2012. For additional information about our proved reserves and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, see Properties – Proved Reserves under Part I, Item 2 of this Form 10-K.

We seek to increase our reserves through acquisitions, drilling, recompletions and workovers. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to add reserves, production and cash flow post-acquisition. Our acquisition team continues to work diligently to find properties that will fit our profile and that we believe will add strategic and financial value to our company.

In October 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”), certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”). Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 61% natural gas, 36% oil and 3% NGLs, all of which were classified as proved developed.

In May 2011, we acquired from Opal Resources LLC and Opal Resources Operating Company LLC (collectively, “Opal”) certain oil and gas leasehold interests in the Permian Basin of West Texas, which we refer to as our “Yellow Rose Properties.” Internal estimates of proved reserves associated with the Yellow Rose Properties as of the acquisition date were approximately 30.1 MMBoe (180.4 Bcfe), comprised of approximately 69% oil, 22% NGLs and 9% natural gas, and approximately 70% of such reserves were classified as proved undeveloped.

In August 2011, we acquired from Shell Offshore Inc. (“Shell”) its 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas treatment plant (collectively, the “Fairway Properties”). Internal estimates of proved reserves associated with the Fairway Properties as of the acquisition date were 8.9 MMBoe (53.5 Bcfe), comprised of approximately 72% natural gas, 27% NGLs and less than 1% oil, all of which are proved developed producing.

From time to time, as part of our business strategy, we sell various properties. In 2012, we sold our 40%, non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico. In 2011 and 2010, there were no property sales of significance.

Additional information on these acquisitions and this divestiture can be found in Properties under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and in Financial Statements – Note 2 – Acquisitions and Divestitures under Part II, Item 8 of this Form 10-K.

Our exploration efforts historically have been in areas in reasonably close proximity to known proved reserves, but in 2013, some of our planned exploration projects are higher risk with potentially higher returns than our historical risk/reward profile. Historically, we have financed our drilling capital expenditures with operating cash flow. The investment associated with drilling an offshore well and future development of an offshore project principally depends upon water depth, the depth of the well, the complexity of the geological formations involved and whether the well or project can be connected to existing infrastructure or will require additional investment in infrastructure. Deepwater and deep shelf drilling projects can be substantially more capital intensive than those on the conventional shelf and onshore. Certain risks are inherent in the oil and natural gas industry and our business, any one of which, if it occurs, can negatively impact our rate of return on shareholders’ equity. When projects are extremely capital intensive and involve substantial risk, we often seek participants to share the risk. Onshore wells are less capital intensive than offshore wells, but the amount of reserves discovered and developed on a per well basis has historically been less from onshore wells than from offshore wells. We drilled four, eight and six successful offshore wells (gross) in 2012, 2011 and 2010, respectively and drilled 77 and 39 successful onshore wells (gross) in 2012 and 2011, respectively.

We generally sell our oil, NGLs and natural gas at the wellhead at current market prices or transport our production to “pooling points” where it is sold. We are required to pay gathering and transportation costs with respect to a majority of our products. Our products are marketed several different ways depending upon a number of factors including the availability of purchasers at the wellhead, the availability and cost of pipelines near the well or related production platforms, the availability of third-party processing capacity, market prices, pipeline constraints and operational flexibility.

amounts for facilities capital, recompletions, seismic and leasehold items. Geographically, the budget includes 63% for offshore (11 wells) and 37% for onshore. The budget for offshore includes two deepwater wells and a joint interest arrangement in another deepwater well, of which we are not the operator. The budget for onshore includes 27 wells in the Yellow Rose Properties and amounts currently designated for our Terry County and East Texas prospects for completion work and additional wells, which require further evaluation. Thus far in 2013, we have not closed any acquisitions, but we continue to evaluate and bid on opportunities as they arise. We anticipate funding our 2013 capital budget and any potential acquisitions with cash flow from operating activities, cash on hand, borrowings under our revolving bank credit facility and by accessing the capital markets to the extent necessary. Our 2013 capital budget is subject to change as conditions warrant. We strive to be as flexible as possible and believe this strategy holds the best promise for value creation and growth and managing the volatility inherent in our business.

Business Strategy

We plan to continue to acquire, explore and develop oil and natural gas reserves on the Outer Continental Shelf (“OCS”), the area of our historical success and technical expertise, which we believe will yield rates of return sufficient to remain competitive in our industry. We believe attractive acquisition opportunities will continue to arise in the Gulf of Mexico as the major integrated oil companies and other large independent oil and gas exploration and production companies continue to divest properties to focus on larger and more capital-intensive projects that better match their long-term strategic goals. Because of ongoing market volatility and, more specifically, the significant decline in natural gas prices during the past several years, we also believe that other less well-capitalized producers may seek buyers for their properties both onshore and offshore, which could create opportunities for us.

We believe a portion of our Gulf of Mexico acreage has exploration potential below currently producing zones, including deep shelf reserves at subsurface depths greater than 15,000 feet. Although the cost to drill deep shelf wells is usually significantly higher than shallower wells, the reserve targets are typically larger and the use of existing infrastructure, when available, can increase the economic potential of these wells.

In addition to pursuing opportunities in the Gulf of Mexico, we plan to continue to pursue other areas that are compatible with our technical expertise and could yield rates of return sufficient to remain competitive in our industry. As described above, we have acquired interests in various onshore properties in Texas and anticipate acquiring or expanding our onshore holdings through exploration, development and acquisition activities.

We believe our business approach has contributed to our success and has positioned us to capitalize on new opportunities. Historically, we have limited our annual capital spending for drilling activities to operating cash flow, and we have used capacity under our revolving bank credit facility for acquisitions, development and to balance working capital fluctuations.

Competition

The oil and natural gas industry is highly competitive. We currently operate in the Gulf of Mexico and onshore in Texas and compete for the acquisition of oil and natural gas properties primarily on the basis of price for such properties. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well established companies and have financial and other resources substantially greater than ours. Our ability to acquire additional oil and natural gas properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. For a more thorough discussion of how competition could impact our ability to successfully complete our business strategy, see Risk Factors in Part I, Item 1A of this Form 10-K.

Oil and Natural Gas Marketing and Delivery Commitments

We sell our oil, NGLs and natural gas to third-party purchasers. We are not dependent upon, or contractually limited to, any one purchaser or small group of purchasers. However, in 2012 approximately 35% of our sales were to Shell Trading (US) Co. and approximately 16% of our sales were to ConocoPhillips Company and Phillips66 Company on a combined basis, which became separate companies during 2012. See Financial Statements – Note 1 – Significant Accounting Policies – Concentration of Credit Risk in Part II, Item 8 of this Form 10-K for additional information about our sales to customers. Due to the nature of oil and natural gas markets and because oil and natural gas are freely traded commodities with numerous purchasers in the Gulf of Mexico and Texas, we do not believe the loss of a single purchaser or a few purchasers would materially affect our ability to sell our production. We do not have any agreements which obligate us to deliver material quantities to third parties.

Regulation

General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting wellhead sales of natural gas, effective January 1, 1993. While sales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

In addition, the Federal Trade Commission, the FERC and the Commodity Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

Regulation and transportation 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 like 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 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 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. The rates for such storage and transportation services are subject to FERC ratemaking authority, and FERC exercises its authority either by applying cost-of-service principles or granting market based rates.

Similarly, the natural gas pipeline industry may also be subject to state regulations which may change from time to time. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (“Competition Bill”) and H.B. 1920 (“LUG Bill”). The Competition Bill gives the Railroad Commission of Texas (“RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering

and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. The RRC was subject to a sunset condition. Although certain proposals were made in 2012, no legislation was enacted during 2012. The RRC will be reviewed again in 2013.

The Outer Continental Shelf Lands Act (“OCSLA”), which is administered by the Bureau of Ocean Energy Management (“BOEM”) and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers working in the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. On June 18, 2008, the BOEM issued a final rule, effective August 18, 2008, that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.

In December 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as W&T, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtus”) during a calendar year must annually report, starting May 1, 2009, such sales and purchases to the FERC. 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.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated. As a result, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

While the changes by these federal and state regulators for the most part affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC, the BOEM or state regulators will take on these matters; however, we do not believe that any such action taken will affect us differently, in any material way, than other natural gas producers with which we compete.

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

In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. As it relates to intrastate crude oil, condensate and 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 or natural gas liquids pipelines will affect us in a way that materially differs from the way they affect other crude oil, condensate and natural gas liquids producers or marketers.

Regulation of oil and natural gas exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of oil and gas resources, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing of such wells.

Federal leases. Most of our offshore operations are conducted on federal oil and natural gas leases, which are administered by the BOEM pursuant to the OCSLA. These leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEM, Bureau of Safety and Environmental Enforcement (“BSEE”), and other government agency regulations and orders that are subject to interpretation and change. The BOEM and BSEE have promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines. See Risk Factors under Part I, Item 1A in this Form 10-K for more information on new regulations and interpretations.

To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. W&T Offshore, Inc. is currently exempt from supplemental bonding requirements by the BOEM. As many BOEM regulations are being reviewed, we may be subject to supplemental bonding requirements in the future. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations. See Risk Factors – BP’s Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the Gulf of Mexico, some of which may be unforeseeable under Part I, Item 1A in this Form 10-K for more information.

The Office of Natural Resources Revenue (“ONRR”) administers the collection of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the ONRR and the BOEM.

Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. The BOEM and the BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, the BOEM and the BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by the BOEM and the BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs and/or capital expenditures.

Environmental regulations. We are subject to stringent federal, state and local environmental laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and producing operations, the amounts and types of materials that may be released into the environment, the discharge and disposal of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce

such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. The remediation, reclamation and abandonment of wells, platforms and other facilities in the Gulf of Mexico may require us to incur significant costs. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.

We believe we are in substantial compliance with current applicable environmental laws and regulations. We believe that compliance with existing requirements will not have a material adverse impact on our operations, but failure to comply could have material consequences. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities related to compliance with environmental laws and regulations will not be incurred in the future.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons are subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third-party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.

The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”), regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.” Disposal of such non-hazardous oil and natural gas exploration, development and production wastes is usually regulated by state law. Other wastes handled at exploration and production sites or generated in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes,” thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating costs as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.

Air emissions from our operations are subject to the Clean Air Act (“CAA”) and comparable state and local requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In August 2012, the U.S. Environmental Protection Agency (the “EPA”) adopted new rules that establish air emission controls requirements for oil and natural gas production and natural gas processing operations. Specifically, the EPA established New Source Performance Standards for emissions of sulfur dioxide and volatile

organic compounds (“VOCs”) and a separate set of emission standards for hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA 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 any hydrocarbons 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 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 operating results. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

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 has 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 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, such as petroleum refineries, on an annual basis effective in 2011, 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 we are in compliance with this new emission reporting requirement as it applies to our operations

The United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or 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, NGLs 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 primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”) which amends and augments oil spill provisions of the Clean Water Act. OPA imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters, including the OCS or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial

threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several, strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. 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. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to a maximum of $150 million. We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS. As a result of the BP Deepwater Horizon incident, legislation has been proposed in Congress to increase the minimum level of financial responsibility to $300 million or more. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether 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 an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation and Insurance Claims in Part II, Item 7 of this Form 10-K for additional information on insurance coverage.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Effective February 1, 2012, the RRC began requiring all operators to disclose on a public website the chemical ingredients and water volumes used to hydraulically fracture wells in Texas. We follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities including disclosure requirements. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells that require hydraulic fracturing.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA is performing a study of the potential environmental effects of hydraulic fracturing on drinking 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, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report in 2014. The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”) in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.

Federal Lease Stipulations include regulations regarding the taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). The BSEE also issues numerous regulations under the nomenclature Notice to Lessees (“NTL”) that provide formal guidelines on implementation of OCS regulations and standards. We believe we are in compliance in all material respects with the requirements regarding protection of marine species.

Certain flora and fauna that have been officially classified as “threatened” or “endangered” are protected by the Endangered Species Act. This law prohibits any activities that could “take” a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area where we wish to conduct seismic surveys, development or abandonment operations, the work could be prohibited or delayed or expensive mitigation could be required.

Our oil and natural gas operations include a production platform in the Gulf of Mexico located in a National Marine Sanctuary. As a result, we are subject to additional federal regulation, including regulations issued by the National Oceanic and Atmospheric Administration. Unique regulations related to operations in a sanctuary include prohibition of drilling activities within certain protected areas, restrictions on the types of water and other substances that may be discharged, required depths of discharge in connection with drilling and production activities and limitations on mooring of vessels. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief.

Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Magnuson-Stevens Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands. These and other protected areas may require certain mitigation measures to avoid harm to wildlife, and such laws and regulations may impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. Naturally Occurring Radioactive Materials (“NORM”) may contaminate minerals extraction and processing equipment used in the oil and natural gas industry. The waste resulting from such contamination is regulated by federal and state laws. Standards have been developed for worker protection; treatment, storage and disposal of NORM and NORM waste; management of waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. We do not anticipate any material expenditures in connection with our compliance with RCRA and applicable state laws related to NORM waste.

We maintain liability insurance and well control insurance for all of our operations. In addition, we maintain property and hurricane damage insurance coverage for some, but not all, of our properties, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain does not cover the risks described above from gradual pollution events which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover such risks or that such insurance

will be available at a cost that would justify its purchase. The occurrence of a significant environmental event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.

Seasonality

For a discussion of seasonal changes that affect our business, see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Inflation and Seasonality under Part II, Item 7 of this Form 10-K.

Employees

As of December 31, 2012, we employed 337 people. We are not a party to any collective bargaining agreements and we have not experienced any strikes or work stoppages. We consider our relations with our employees to be good.

Additional Information

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.wtoffshore.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., Nine Greenway Plaza, Suite 300, Houston, Texas 77046 or by calling (713) 297-8024. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Information on our website is not a part of this Form 10-K.

Item 1A.

Risk Factors

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to us and our industry could materially impact our future performance and results of operations. We have provided below a list of known material risk factors that should be reviewed when considering our securities. These are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.

Risks Relating to the Oil and Natural Gas Industry and Our Business

A substantial or extended decline in oil, NGLs and natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.

The price we receive for our oil, NGLs and natural gas production directly affects our revenues, profitability, access to capital and future rate of growth. Oil, NGLs and natural gas are commodities and are subject to wide price fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, NGLs and natural gas have been volatile and will likely continue to be volatile in the future. The prices we receive for our production and the volume of our production depend on numerous factors beyond our control. These factors include the following:

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changes in global supply and demand for oil, NGLs and natural gas;

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the actions of the Organization of Petroleum Exporting Countries;

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the price and quantity of imports of foreign oil, NGLs, natural gas and liquefied natural gas;

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acts of war, terrorism or political instability in oil producing countries;

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economic conditions;

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political conditions and events, including embargoes, affecting oil-producing activity;

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the level of global oil and natural gas exploration and production activity;

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the level of global oil, NGLs and natural gas inventories;

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weather conditions;

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technological advances affecting energy consumption;

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the price and availability of alternative fuels; and

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geographic differences in pricing.

Lower prices for our oil, NGLs and natural gas production may not only decrease our revenues on a per unit basis but may also reduce the amount of oil, NGLs and natural gas that we can produce economically. For example, the prices of oil and natural gas declined substantially during the second half of 2008 and impacted production volumes. Natural gas and NGLs prices have been negatively affected by excess natural gas production, high levels of stored natural gas and weather conditions affecting demand. There have been significant recent development activities in shale and other resource plays, which have the potential to yield a significant amount of natural gas and NGLs production, as well as natural gas and NGLs produced in connection with increased domestic oil drilling activities. The potential increases in natural gas supplies resulting from the large-scale development of these unconventional resource reserves could continue to have an adverse impact on the price of natural gas and NGLs. An environment of depressed oil, NGLs and natural gas prices would materially and adversely affect our future business, financial condition, results of operations, liquidity and/or ability to finance planned capital expenditures.

If oil, NGLs and natural gas prices decrease, we may be required to write down the carrying values and/or the estimates of total reserves of our oil and natural gas properties.

Accounting rules applicable to us require that we periodically review the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. Primarily as a result of the significant decline in both oil and natural gas prices as of December 31, 2008, we recorded a ceiling test impairment at December 31, 2008 of $1.2 billion. Additionally, we recorded a ceiling test impairment at March 31, 2009 of $218.9 million primarily as a result of a further decline in natural gas prices as of March 31, 2009. We did not have any impairment write-downs in 2012, 2011 or 2010. Declines in oil, NGLs and natural gas prices after December 31, 2012 may require us to record additional ceiling test impairments in the future. No assurance can be given that we will not experience a ceiling test impairment in future periods, which could have a material adverse effect on our results of operations in the period taken. As a result of lower oil, NGLs and natural gas prices, we may also reduce our estimates of the reserves that may be economically recovered, which would reduce the total value of our proved reserves. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Impairment of oil and natural gas properties in Part II, Item 7 and Financial Statements – Note 1 – Significant Accounting Policies in Part II, Item 8 of this Form 10-K for additional information on the ceiling test.

The Company could pay additional penalties and certain operating activities could be restricted if it does not comply with the terms of an agreement with certain government entities.

The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the EPA conducted a federal grand jury investigation beginning in late 2010 of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms

in the Gulf of Mexico in 2009. In December 2012, an agreement was reached that resolves these environmental violations and the agreement was approved by the federal district court in January 2013. Under the agreement, the Company on January 3, 2013 (i) pled guilty to one felony count under the Clean Water Act for altering monthly produced water discharge samples for the Ewing Banks 910 platform in 2009 and one misdemeanor count under the Clean Water Act for negligently discharging a small amount of oil from the same platform in November 2009 and (ii) paid a $0.7 million fine and $0.3 million for community service and (iii) entered into an environmental compliance program subject to a third-party audit. Under the agreement, the Company was placed on a three-year term of probation. The probation terms require that the Company: a) commit no further criminal violations, b) pay in full amounts pursuant to the agreement, c) comply with an Environmental Compliance Plan during the probation period, and d) take no adverse action against personnel who cooperated in the investigation. The agreement further stipulates that the Government will not seek any further criminal charges against the Company in this matter. Failure to comply with the terms of the agreement could lead to further penalties and/or operating restrictions.

The Company is responding to a qui tam action filed under the Federal False Claims Act which could have a material adverse effect upon us.

On September 21, 2012, we were served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of a Company contractor. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494, was filed in the United States District Court for the Eastern District of Louisiana, against the Company and three other working interest owners related to claims associated with three of the Company’s operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. The complaint was originally filed in 2010 but kept under confidential seal in order for the federal government to decide if it wished to intervene and take over the prosecution of the qui tam action. The government declined to intervene in this suit and the complaint was unsealed and made public in June 2012, thereby giving the plaintiff the opportunity to pursue the claims on behalf of the government.

The complaint alleges that environmental violations at three of our operated production platforms in the Gulf of Mexico violate the federal offshore lease provisions so that we, among other things, wrongfully retained benefits under the applicable leases. The alleged environmental violations include allegations of discharges of relatively small amounts of oil into the Gulf of Mexico, the failure to report and record such discharges, and falsification of certain produced water samples and related reports required under federal law. The events are alleged to have occurred in 2009. These are largely the same allegations involved in the federal grand jury investigation described above. We have filed a motion to dismiss the claim. The plaintiff dismissed his claims against the three other working interest owners after they filed motions to dismiss. The plaintiff conceded that certain of his claims should be dismissed in his reply to the Company’s motion to dismiss. The motion remains pending before the court.

The Company has been sued by certain landowners alleging damages to their properties.

Since 2009, certain Cameron Parish landowners have filed suits in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and Tracy W. Krohn as well as several other defendants unrelated to us. In their lawsuits, plaintiffs are alleging that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and are seeking compensatory and punitive damages. During 2012, we settled claims with certain landowners and paid $10.0 million. We assessed the remaining claims to be probable and have accrued $1.3 million in our contingent liabilities as of December 31, 2012. However, we cannot state with certainty that our estimates of additional exposure are accurate concerning this matter.

BP’s Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the Gulf of Mexico, some of which may be unforeseeable.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals, and substantial rules adopted, by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. Beginning in May 2010, the BOEM and BSEE issued a series of NTLs imposing a variety of new safety measures and permitting requirements. They also imposed a six-month moratorium on drilling activities in federal offshore waters that stretched into a much longer moratorium resulting in delays in not only deepwater drilling but also in many other types of activities in the Gulf of Mexico that continue to exist currently.

In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEM and BSEE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico more difficult, more time consuming, and more costly. For example, a variety of amendments to the OPA have been proposed in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the OCS, which includes the Gulf of Mexico where we have substantial offshore operations. OPA subjects operators of offshore leases and owners and operators 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, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. OPA also requires operators to provide evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS. Legislation has been proposed in Congress to amend OPA to increase the minimum level of financial responsibility to $300 million or more. If the minimum level of financial responsibility is increased further, we may experience difficulty in providing financial assurances sufficient to comply with the revised requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased further.

Other significant regulatory changes since the Deepwater Horizon event are regulations related to assessing the potential environmental impact of future spills using worse case discharge scenarios on a well-by-well basis, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time it takes to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, the risk to our business may be increased. The permitting process is slower and inconsistent for deep water work, shallow water work and even for plug and abandonment activities. This could lead to increased costs and performing work at less than optimal effectiveness. We have not experienced delays in obtaining permits related to our onshore operations.

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

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

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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.

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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.

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The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system (“SEMS”) in order 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 BSEE.

As a result of the issuance of these new NTLs and the new regulatory requirements, the BOEM has been taking longer to review and approve permits for new wells than was common prior to the Deepwater Horizon incident. These NTLs 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. The delay in granting permits could also cause some of our leases to lapse as a result of failure to commence drilling or continue production operations.

New requirements imposed by the BOEM and BSEE could significantly impact the cost of operating our business.

In addition to the NTLs discussed previously, the BOEM issued NTL No. 2010-G05 dated effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” – wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease – in the Gulf of Mexico. This NTL sets forth more stringent standards for decommissioning timing requirements by requiring that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts which could cause an increase, perhaps materially, in our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future ARO required to meet such increased costs. In 2010, we increased our estimate of ARO based on our expected acceleration in timing for such obligations as a result of implementing this NTL. In 2012, after receiving further interpretations of the regulations from the BOEM, the scope of the work increased and the determination of final requirements increased the amount of work involved. As a result of this effort, along with other work scope changes, we increased our estimate of ARO again in 2012. The increase in decommissioning activity in the Gulf of Mexico expected over the next few years as a result of the NTL may result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related ARO.

Recently proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs.

In August 2012, the EPA adopted new regulations under the CAA that, among other things, require additional emissions controls for natural gas and NGLs production, including New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require, among other things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could significantly increase our costs of development and production.

Lower oil and natural gas prices could negatively impact our ability to borrow.

As of December 31, 2012, available borrowings under our revolving bank credit facility are currently limited to $725.0 million, less outstanding borrowings and letters of credit. Availability is determined semi-annually by our lenders and is based on oil, NGLs and natural gas prices and on our proved reserves. Substantially all of our oil and natural gas properties are pledged as collateral under the credit agreement governing our revolving bank credit facility (the “Credit Agreement”). The Credit Agreement limits our ability to incur additional indebtedness based on specified financial covenants, ratios or other criteria. Lower oil, NGLs and natural gas prices in the future could result in a reduction in credit availability and also affect our ability to satisfy these covenants, ratios or other criteria and thus could reduce our ability to incur additional indebtedness and our ability to replace reserves.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We could be exposed to uninsured losses in the future. The occurrence of a significant accident or other event not covered in whole or in part by our insurance could have a material adverse impact on our financial condition and operations. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. In May and June 2012, we renewed our insurance policies covering well control and hurricane damage at an annual cost of approximately $30.6 million. A retention amount of $5.0 million for well control events and $40.5 million per hurricane occurrence must be satisfied by us before we are indemnified for losses. In addition, pollution and environmental risks are generally not fully insurable as gradual seepage and pollution are not covered under our policies. Because third-party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented.

See Financial Statements – Note 3 – Hurricane Remediation and Insurance Claims and – Note 18 – Contingencies under Part II, Item 8 of this Form 10-K for additional information on legal issues regarding our insurance coverage.

Insurance for well control and hurricane damage may become significantly more expensive for less coverage, and some losses currently covered by insurance may not be covered in the future.

Due to insurance claims in recent years associated with hurricanes in the Gulf of Mexico and global catastrophic losses, property damage and well control insurance coverage has become more limited and the cost of such coverage has become both more costly and more volatile. The insurance market may change dramatically in the future due to the major oil spill that occurred in 2010 at BP’s Macondo well in the deepwater Gulf of

Mexico. As of December 31, 2012, approximately 91% of our PV-10 value of proved reserves attributable to our Gulf of Mexico properties is on platforms that are covered under our current insurance policies for named windstorm damage. Our insurers may not continue to offer us the type and level of our current coverage, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurance companies will not pay our claims. The occurrence of any or all of these possibilities could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have a claim, the insurance companies will not pay our claim.

Commodity derivative positions may limit our potential gains.

In order to manage our exposure to price risk in the marketing of our oil and natural gas, we may periodically enter into oil and natural gas price commodity derivative positions with respect to a portion of our expected production. While these commodity derivative positions are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income if oil and natural gas prices were to rise substantially over the price established by such positions. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

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our production is less than expected;

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there is a widening of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements; or

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the counterparties to the derivative contracts fail to perform under the terms of the contracts.

See Financial Statements – Note 6 – Derivative Financial Instruments under Part II, Item 8 of this Form 10-K for additional information on derivative transactions.

We may be limited in our ability to maintain proved undeveloped reserves under current SEC guidance.

Current SEC guidance requires proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped.

As of December 31, 2012, approximately 26% of our total proved reserves were undeveloped and approximately 21% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be developed or produced.

We are not the operator with respect to approximately 14% of our proved developed non-producing reserves, so we may not be in a position to control the timing of all development activities. Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.

If we are not able to replace reserves, we will not be able to sustain production at current levels.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful exploration, development or acquisition activities, our proved reserves and production will decline over time. By their nature, estimates of undeveloped reserves are less certain. Recovery of undeveloped reserves could require

significant capital expenditures and successful drilling operations. Our future oil and natural gas reserves, production, and therefore our cash flow and net income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

Relatively short production periods for our Gulf of Mexico properties subject us to high reserve replacement needs and require significant capital expenditures to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace those reserves would result in decreasing reserves, production and cash flows over time.

Unless we conduct successful development and exploration activities at sufficient levels or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves during the initial few years of production. The majority of our current production is from the Gulf of Mexico. Production from reservoirs in the Gulf of Mexico generally decline more rapidly than from reservoirs in many other producing regions of the United States. Our independent petroleum consultant estimates that, on average, 43% of our total proved reserves are depleted within three years. As a result, our need to replace reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their reserves over a similar time period, such as those producers who have a larger portion of their reserves in areas other than the Gulf of Mexico. We may not be able to develop, find or acquire additional reserves in sufficient quantities to sustain our current production levels or to grow production beyond current levels. In addition, due to the significant time requirements involved with exploration and development activities, particularly for wells in the deepwater or wells not located near existing infrastructure, actual oil and natural gas production from new wells may not occur, if at all, for a considerable period of time following the commencement of any particular project.

Significant capital expenditures are required to replace our reserves.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, securities offerings and bank borrowings. In order to finance future capital expenditures, we may need to alter or increase our capitalization substantially through the issuance of additional debt or equity securities, bank borrowings, reserve-based loans, joint ventures or other means. These changes in capitalization may significantly affect our financial risk profile.

Future cash flows are subject to a number of variables, such as the level of production from existing wells, the prices of oil, NGLs and natural gas, and our success in developing and producing new reserves. Any reductions in our capital expenditures to stay within internally generated cash flow (which could be adversely affected by declining commodity prices) and cash on hand will make replacing produced reserves more difficult. If our cash flow from operations and cash on hand are not sufficient to fund our capital expenditure budget, we may not be able to access additional debt, equity or other methods of financing on an economic or timely basis to replace our proved reserves.

Competition for oil and natural gas properties and prospects is intense; some of our competitors have larger financial, technical and personnel resources that may give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil, NGLs and natural gas and securing trained personnel. Many of our competitors have financial resources that allow them to obtain substantially greater technical expertise and personnel than we have. We actively compete with other companies in our industry when acquiring new leases or oil and natural gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to

the highest bidder. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. On the acquisition opportunities made available to us, we compete with other companies in our industry for such properties through a private bidding process, direct negotiations or some combination thereof. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted. The availability of properties for acquisition depends largely on the divesting practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors we cannot control or influence.

We conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which presents unique operating risks.

The deep shelf and the deepwater of the Gulf of Mexico are areas that have had less drilling activity due, in part, to their geological complexity, depth and higher cost to drill and ultimately develop. There are additional risks associated with deep shelf and deepwater drilling that could result in substantial cost overruns and/or result in uneconomic projects or wells. Deeper targets are more difficult to interpret with traditional seismic processing. Moreover, drilling costs and the risk of mechanical failure are significantly higher because of the additional depth and adverse conditions, such as high temperature and pressure. For example, the drilling of deepwater wells requires specific types of rigs with significantly higher day rates and limited availability, as compared to the rigs used in shallower water. Deepwater wells have greater mechanical risks because the wellhead equipment is installed on the sea floor. Deepwater development costs can be significantly higher than development costs for wells drilled on the conventional shelf because deepwater drilling requires larger installation equipment, sophisticated sea floor production handling equipment, expensive, state-of-the-art platforms and/or investment in infrastructure. Deep shelf development can also be more expensive than conventional shelf projects because deep shelf development requires more drilling days and higher drilling and service costs due to extreme pressure and temperatures associated with greater depths. Accordingly, we cannot assure you that our oil and natural gas exploration activities in the deep shelf, the deepwater and elsewhere will be commercially successful.

Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico.

We are required to record a liability for the present value of our ARO 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 Gulf of Mexico 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 ARO in future periods. For example, because we operate in the Gulf of Mexico, 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 ARO could differ dramatically from what we may ultimately incur as a result of platform damage.

As described above in the risk factor titled “New requirements recently imposed by the BOEM and BSEE could significantly impact the cost of operating our business,” the BOEM’s NTL 2010-G05 increased our liability for ARO by accelerating the time frame for plugging, abandonment and removal for some of our platforms and the BOEM further increased our liability after issuing regulation interpretations which affected

scope and requirements. In addition, the potential increase in decommissioning activity in the Gulf of Mexico over the next several years as a result of the NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related ARO.

We may not be in a position to control the timing of development efforts, associated costs or the rate of production of the reserves from our non-operated properties.

As we carry out our drilling program, we may not serve as operator of all planned wells. We have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities. The success and timing of exploration and development activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

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the timing and amount of capital expenditures;

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the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

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the operator’s expertise and financial resources;

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approval of other participants in drilling wells and such participants’ financial resources;

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selection of technology; and

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the rate of production of the reserves.

Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development activities may be unsuccessful for many reasons, including adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages, geological issues and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not assure us that we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells hinder our efforts to replace reserves.

Our oil and natural gas exploration and production activities, including well stimulation and completion activities which include, among other things, hydraulic fracturing, involve a variety of operating risks, including:

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fires;

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explosions;

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blow-outs and surface cratering;

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uncontrollable flows of natural gas, oil and formation water;

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natural disasters, such as tropical storms, hurricanes and other adverse weather conditions;

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inability to obtain insurance at reasonable rates;

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failure to receive payment on insurance claims in a timely manner, or for the full amount claimed;

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pipe, cement, subsea well or pipeline failures;

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casing collapses or failures;

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mechanical difficulties, such as lost or stuck oil field drilling and service tools;

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abnormally pressured formations or rock compaction; and

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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, encountering NORM, and discharges of brine, well stimulation and completion fluids, toxic gases, or other pollutants into the surface and subsurface environment.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

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injury or loss of life;

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damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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clean-up responsibilities;

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regulatory investigation and penalties;

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suspension of our operations;

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repairs required to resume operations; and

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loss of reserves.

Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from tropical storms, hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate funds available for exploration, development and acquisitions or result in the loss of property and equipment.

The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenues or curtailment of production from factors specifically affecting the Gulf of Mexico.

The geographic concentration of our properties along the U.S. Gulf Coast and adjacent waters on and beyond the outer continental shelf means that some or all of our properties could be affected by the same event should the Gulf of Mexico experience:

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severe weather, including tropical storms and hurricanes;

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

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changes in the status of pipelines that we depend on for transportation of our production to the marketplace;

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delays or decreases in the availability of capacity to transport, gather or process production; or

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changes in the regulatory environment.

Because a majority of our properties could experience the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area. For example, in 2009, net production of approximately 8.7 Bcfe was deferred as a result of damage caused primarily by Hurricane Ike and, in 2012, Hurricane Isaac resulted in the deferral of approximately 2.9 Bcfe.

As we increase our onshore operations, we will be subject to different risk factors that could impact loss of revenues or curtailment of production for these geographies.

Onshore oil and gas exploration and production operations share similar risk factors to offshore, but also have some different regulations, interpretation of regulations and enforcement by the particular state in which the operations are conducted. Until 2011, our experience has primarily been with offshore operations. We are subject to and must comply with the various state regulations and work effectively with the state agencies, and failure to do so may impact our operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight rock formations. We utilize hydraulic fracturing techniques in connection with developing our recently acquired Yellow Rose Properties and other onshore properties. 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. The EPA, however, recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA Underground Injection Control Program. In addition, the EPA has commenced a broad study of the potential environmental effects of hydraulic fracturing activities, and the agency has indicated that it expects to issue its study report in late 2014. A number of other federal agencies, including the U.S. Department of Energy, Department of Interior, and White House Council on Environmental Quality, are also studying various aspects of hydraulic fracturing. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Legislation also has been introduced before 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 and local governments have adopted, and other states and local governments 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 RRC began requiring all operators to disclose on a public website the chemical ingredients and water volumes used to hydraulically fracture wells in Texas. 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 associated permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Properties that we acquire may not produce as projected and we may be unable to immediately identify liabilities associated with these properties or obtain protection from sellers against them.

Our business strategy includes growing by making acquisitions, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests. Our acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:

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acceptable prices for available properties;

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amounts of recoverable reserves;

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estimates of future oil, NGLs and natural gas prices;

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estimates of future exploratory, development and operating costs;

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estimates of the costs and timing of plugging and abandonment; and

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estimates of potential environmental and other liabilities.

Our assessment of the acquired properties will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies. In the course of our due diligence, we have historically not physically inspected every well, platform or pipeline. Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.

Increasing our reserve base through acquisitions is an important part of our business strategy. We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses. In particular, we may face significant challenges in consolidating functions and integrating procedures, personnel and operations in an effective manner. The failure to successfully integrate such properties or businesses into our business may adversely affect our business and results of operations. Any acquisition we make may involve numerous risks, including:

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a significant increase in our indebtedness and working capital requirements;

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the inability to timely and effectively integrate the operations of recently acquired businesses or assets;

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the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets before our acquisition;

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our lack of drilling history in the geographic areas in which the acquired business operates;

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customer or key employee loss from the acquired business;

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increased administration of new personnel;

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additional costs due to increased scope and complexity of our operations; and

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potential disruption of our ongoing business.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. To the extent that we acquire properties substantially different from the properties in our primary operating region or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as with acquisitions within our primary operating region. We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make.

Estimates of our proved reserves depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in the estimates or underlying assumptions will materially affect the quantities of and present value of future net revenues from our proved reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of our reserves at December 31, 2012. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Oil and natural gas reserve quantities, Part II, Item 7 for a discussion of the estimates and assumptions about our estimated oil and natural gas reserves information reported in Business in Part I, Item 1, Properties in Part I, Item 2 and Financial Statements – Note 21 – Supplemental Oil and Gas Disclosures in Part II, Item 8 of this Form 10-K.

In order to prepare our year-end reserve estimates, our independent petroleum consultant projected our production rates and timing of development expenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary and may not be under our control. The process also requires economic assumptions about matters such as oil and natural gas prices, operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved oil and natural gas reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Prospects that we decide to drill may not yield oil or natural gas in commercial quantities or quantities sufficient to meet our targeted rate of return.

A prospect is an area of land in which we own an interest, could acquire an interest or have operating rights, and have what our geoscientists believe, based on available seismic and geological information, to be indications of economic accumulations of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analysis we perform using data from other wells, more fully explored prospects and/or producing fields will accurately predict the characteristics and potential reserves associated with our drilling prospects. To the extent we drill additional wells in the deepwater and/or on the deep shelf, our drilling activities could become more expensive. In addition, the geological complexity of deepwater, deep shelf and various onshore formations may make it more difficult for us to sustain our historical rates of drilling success. As a result, we can offer no assurance that we will find commercial quantities of oil and natural gas and, therefore, we can offer no assurance that we will achieve positive rates of return on our investments.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities, which in most cases are owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells because of a reduction in demand for our production or because of inadequacy or unavailability of pipelines or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market. We have, in the past, been required to shut in wells when hurricanes have caused or threatened damage to pipelines and gathering stations. For example, in September

2008, as a result of Hurricane Ike, two of our operated platforms and eight non-operated platforms were toppled and a number of platforms, third-party pipelines and processing facilities upon which we depend to deliver our production to the marketplace were damaged. In 2012, under threat of Hurricane Isaac, we shut in most of our offshore production for a period of 10 to 25 days.

In some cases, our wells are tied back to platforms owned by parties who do not have an economic interest in our wells and we cannot be assured that such parties will continue to process our oil and natural gas.

Currently, a portion of our oil and natural gas is processed for sale on platforms owned by parties with no economic interest in our wells and no other processing facilities would be available to process such oil and natural gas without significant investment by us. In addition, third-party platforms could be damaged or destroyed by hurricanes which could reduce or eliminate our ability to market our production. As of December 31, 2012, 10 fields, accounting for approximately 3.7 Bcfe (or 3.6%) of our 2012 production, are tied back to separate, third-party owned platforms. There can be no assurance that the owners of such platforms will continue to process our oil and natural gas production. If any of these platform operators ceases to operate their processing equipment, we may be required to shut in the associated wells or construct additional facilities.

If third-party pipelines connected to our facilities become partially or fully unavailable to transport our natural gas or oil, or if the prices charged by these third-party pipelines increase, our revenues or costs could be adversely affected.

We depend upon third-party pipelines that provide delivery options from our facilities. Because we do not own or operate these pipelines, their continued operation is not within our control. If any of these third-party pipelines become partially or fully unavailable to transport natural gas and oil, or if the gas quality specification for the natural gas pipelines changes so as to restrict our ability to transport natural gas on those pipelines, our revenues could be adversely affected. For example, a third-party pipeline used by our Main Pass 108 field was shut down between June 2010 and March 2011. We estimate this shutdown caused us to defer production of approximately 4.9 Bcfe during 2010 and 3.7 Bcfe during 2011. In 2012, various pipelines were shut down causing production deferral of approximately 1.5 Bcfe with our Matterhorn field being most significantly affected by these shutdowns.

Certain third-party pipelines have submitted or have made plans to submit requests to increase the fees they charge us to use these pipelines. These increased fees could adversely impact our revenues or operating costs, either of which would adversely impact our operating profits and cash flows.

We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration, development, production and transportation of oil and natural gas and operational safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with such legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:

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land use restrictions;

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lease permit restrictions;

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drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;

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spacing of wells;

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unitization and pooling of properties;

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safety precautions;

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operational reporting;

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reporting of natural gas sales for resale; and

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taxation.

Under these laws and regulations, we could be liable for:

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personal injuries;

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property and natural resource damages;

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well site reclamation costs; and

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governmental sanctions, such as fines and penalties.

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and natural gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See Business – Regulation, Part I, Item 1 of this Form 10-K for a more detailed explanation of our regulatory risks.

Our operations may incur substantial liabilities to comply with environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

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require the acquisition of a permit before drilling commences;

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restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

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limit or prohibit exploration or drilling activities on certain lands lying within wilderness, wetlands and other protected areas or that may affect certain wildlife, including marine mammals; and

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impose substantial liabilities for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in:

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the assessment of administrative, civil and criminal penalties;

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loss of our leases;

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incurrence of investigatory or remedial obligations; and

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the imposition of injunctive relief.

In 2012 and in prior years, we have been subject to investigations with respect to allegations that we did not comply with applicable environmental laws and regulations. In December 2012, we reached an agreement with respect to the previously disclosed federal grand jury investigation related to certain violations of environmental laws and regulations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under

these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and regardless of whether our operations met previous standards in the industry at the time they were conducted. Our permits require that we report any incidents that cause or could cause environmental damages. See Business – Regulation, Part I, Item 1 of this Form 10-K for a more detailed description of our environmental risks.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the 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 the warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA has 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 January 2, 2011. The EPA also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, such as petroleum refineries, on an annual basis, beginning in 2011, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or 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, and floods and other climatic events. If any such affects were to occur, they could have an adverse effect on our financial condition and results of operations. Please see – Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, 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 “DF 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 DF Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the DF 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 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 DF 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 DF Act and CFTC rules on us and the timing of such effects.

The DF Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The DF Act and 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 derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the DF 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 DF 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 DF Act is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

We operate a production platform in a highly regulated National Marine Sanctuary, which increases our compliance costs and subjects us to risk of significant fines and penalties if we do not maintain rigorous compliance.

Our oil and natural gas operations include a production platform located in a National Marine Sanctuary in the Gulf of Mexico that is subject to special federal laws and regulations. This production platform is not producing and will be plugged, abandoned and remediated according to regulations. Unique regulations related to operations in the Sanctuary include, among other things, prohibition of drilling activities within certain protected areas, restrictions on substances that may be discharged, depths of discharge in connection with drilling and production activities and limitations on mooring of vessels. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief, including cessation of production from wells associated with this platform.

Our operations could be adversely impacted by security breaches, including cyber-security breaches, which could affect our production of oil and natural gas or could affect other parts of our business.

We face security exposure, including cyber-security exposure, from unauthorized access to our facilities and computer systems. This exposure includes unauthorized access to sensitive information; malicious damage to our facilities, infrastructure, and computer systems; malicious damage to third-party facilities, infrastructure, and computer systems; safety exposure for our employees and contractors; and disruptions of our operations. Although we utilize various procedures and controls to mitigate these exposures, there can be no assurances that these procedures and controls will be sufficient to prevent such events from occurring. Cyber-security exposures in particular are evolving and include malicious software, unauthorized access to confidential data and

disruptions to operations that use computers and data systems. We do not carry business interruption insurance. Any of these security breaches could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

The loss of members of our senior management could adversely affect us.

To a large extent, we depend on the services of our senior management. The loss of the services of any of our senior management, including Tracy W. Krohn, our Founder, Chairman and Chief Executive Officer; Jamie L. Vazquez, our President; John D. Gibbons, our Senior Vice President, Chief Financial Officer and Chief Accounting Officer; Thomas P. Murphy, our Senior Vice President and Chief Operations Officer; Stephen L. Schroeder, our Senior Vice President and Chief Technical Officer; and Thomas F. Getten, our Vice President, General Counsel and Corporate Secretary, could have a negative impact on our operations. We do not maintain or plan to obtain any insurance against the loss of any of these individuals. Please read Executive Officers of the Registrant in Part I following Item 3 in this Form 10-K for more information regarding our senior management team.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

The U.S. oil and natural gas industry may experience significant shortages in the availability of certain drilling rigs as well as significant increases in the cost of utilizing drilling rigs. This could delay or adversely affect our exploration and development operations, which could have a material adverse effect on our business, financial condition or results of operations. If the unavailability or high cost of rigs, equipment, supplies or personnel were particularly severe in the offshore waters of the U.S. Gulf of Mexico or Texas, we could be materially and adversely affected because our operations and properties are concentrated in those areas.

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 has been 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 preferences currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States 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 law could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and production, and any such change could have a negative effect on the results of our operations.

Counterparty credit risk may negatively impact the conversion of our accounts receivables to cash.

Substantially all of our accounts receivable result from oil, NGLs and natural gas sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic or other conditions. In recent years, market conditions resulting in downgrades to credit ratings of energy merchants affected the liquidity of several of our purchasers.

Risks Related to Financings

Adverse changes in the financial and credit markets could negatively impact our economic growth. In addition, declines of oil, NGLs and natural gas prices can affect our ability to obtain funding on acceptable terms or under our current credit facility. These impacts may hinder or prevent us from meeting our future capital needs and may restrict or limit our ability to increase reserves of oil and natural gas.

For 2012 and 2011, world financial markets have been affected from time to time by the instability of the Euro and the uncertainty of some Euro-based countries to repay their debt. In addition, one credit agency downgraded the debt of the U.S. government. These types of events bring uncertainty to the financial markets and may produce volatility and may decrease financing availability.

In recent years, access to financing markets was severely limited at various times. In 2008, prices for oil, NGLs and natural gas had decreased precipitously along with the significant instability that existed in the financial markets during this time. In 2009, the global financial markets and economic conditions were severely distressed. There were concerns, both with respect to bank failures and bank liquidity, as to whether our banks would be able to meet their commitments under credit arrangements in place during that time. These concerns led to very few financing transactions being completed.

We can offer no assurance that we would be able to access the capital market on terms and conditions that would be acceptable to us, if the need were to arise. Our revolving bank credit facility is subject to semi-annual borrowing base determination, and available credit could be reduced or eliminated at the sole discretion of the banks within the facility.

If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due, or we may be unable to implement our exploratory and development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may become insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay off our outstanding indebtedness. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or initiatives by our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our current or any future debt obligations, we may have to undertake alternative financing plans, such as:

•

refinancing or restructuring our debt;

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selling assets;

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reducing or delaying capital investments; or

•

seeking to raise additional capital.

Any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition and results of operations.

Our debt obligations could have important consequences. For example, they could:

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increase our vulnerability to general adverse economic and industry conditions;

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limit our ability to fund future working capital requirements and capital expenditures, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets;

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limit our opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt obligations or to comply with any restrictive terms of our debt obligations;

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

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impair our ability to obtain additional financing in the future; and

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place us at a competitive disadvantage compared to our competitors that have less debt.

In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition, results of operations and cash flows.

Risks Related to Our Principal Shareholder, Tracy W. Krohn

We will be controlled by Tracy W. Krohn as long as he owns a majority of our outstanding common stock, and other shareholders will be unable to affect the outcome of shareholder voting during that time. This control may adversely affect the value of our common stock and inhibit potential changes of control.

Tracy W. Krohn owns and controls 39,562,545 shares of our common stock, representing approximately 52.6% of our voting interests as of February 15, 2013. As a result, Mr. Krohn has the ability to control the outcome of matters that require a simple majority of shareholders for approval and other investors, by themselves, will not be able to affect the outcome of virtually any shareholder vote. Mr. Krohn, subject to any duty owed to our minority shareholders under Texas law, is able to control all matters affecting us, including:

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the composition of our board of directors and, through it, any determination with respect to our business direction and policies, including the appointment and removal of officers;

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the determination of incentive compensation, which may affect our ability to retain key employees;

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any determinations with respect to mergers or other business combinations;

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our acquisition or disposition of assets;

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our financing decisions and our capital raising activities;

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our payment of dividends on our common stock; and

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amendments to our amended and restated articles of incorporation or bylaws.

Mr. Krohn is generally not prohibited from selling a controlling interest in us to a third party. In addition, his concentrated control could discourage others from initiating any potential merger, takeover or other change of control transaction that might be beneficial to our business or stockholders. As a result, the market price of our common stock could be adversely affected.

Due to Mr. Krohn’s ownership and control, we are exempted from many New York Stock Exchange (“NYSE”) corporate governance rules, and, as a result, our other shareholders may not have the protections set forth in those rules, particularly in the event of conflicts of interest with Mr. Krohn.

Mr. Krohn owns a majority of our common stock, and, therefore, we are a “controlled company” within the meaning of the rules of the NYSE. As such, we are not required to comply with certain corporate governance rules of the NYSE that would otherwise apply to us as a listed company on that exchange. These rules are generally intended to increase the likelihood that boards will make decisions in the best interests of shareholders. Should the interests of Mr. Krohn differ from those of other shareholders, the other shareholders will not be afforded the protections of having a majority of directors on the board who are independent from our principal shareholder.

Item 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

LOGO

Our fields are located in the Gulf of Mexico, Alabama and Texas. The offshore fields are found in water depths ranging from less than 10 feet up to 4,900 feet. The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, which typically results in high production rates. The reservoirs in our onshore fields are generally characterized as having low porosity and permeability and require stimulation and artificial lift to produce. The following describes our 10 largest fields as of December 31, 2012, based on quantities of proved reserves on a natural gas equivalent basis. At December 31, 2012, these fields accounted for approximately 82% of our proved reserves.


Field Name	Field Category	Operator	Percent Oil and NGLs of Net Reserves (1)			Percent Natural Gas of Net Reserves (1)			2012 Average Daily Equivalent Sales Rate (Mcfe/d) (1)
Field Name	Field Category	Operator	Percent Oil and NGLs of Net Reserves (1)			Percent Natural Gas of Net Reserves (1)			Gross		Net
Spraberry (Yellow Rose Properties)	Onshore	W&T		89	%		11	%		18,538		15,016
Ship Shoal 349 (Mahogany)	Shelf	W&T		81	%		19	%		26,937		22,896
Viosca Knoll 783 (Tahoe/SE Tahoe)	Deepwater	W&T		27	%		73	%		53,053		36,076
Fairway (Fairway Properties)	Shelf	W&T		29	%		71	%		49,462		27,204
Main Pass 108	Shelf	W&T		19	%		81	%		27,846		21,442
Miss. Canyon 243 (Matterhorn)	Deepwater	W&T		79	%		21	%		23,865		23,865
Viosca Knoll 823 (Virgo)	Deepwater	W&T		36	%		64	%		10,055		6,938
High Island 22	Shelf	W&T		9	%		91	%		470		390
Main Pass 98	Shelf	W&T		21	%		79	%		9,431		7,828
East Cameron 321	Shelf	W&T		91	%		9	%		10,370		8,089

(1)

Thousand cubic feet equivalent – Mcfe. The amount was determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs. The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ significantly.

Our Fields

On December 31, 2012 we had two fields of major significance (having proved reserves which comprise 15% or more of the Company’s total proved reserves, calculated on a natural gas equivalent basis). The Spraberry field (Yellow Rose Properties) is located in the Permian Basin in West Texas and the Ship Shoal 349 field is located on the conventional shelf in the Gulf of Mexico. Below is a description of these fields.

Spraberry Field (Yellow Rose Properties).

The Spraberry field is located in the Permian Basin in West Texas. W&T acquired a 100% working interest in approximately 21,900 net acres in connection with the acquisition of the Yellow Rose Properties in May 2011 and acquired approximately 9,500 net acres earlier in 2011. The Spraberry field was discovered in 1935 and extends over several counties in West Texas comprising about 1.6 million acres. The field is 150 miles long and 75 miles wide, and it has undergone much change and expansion over the years, both aerially and vertically. The correlative interval is now over 3,500 feet thick and includes the Clearfork, Upper Spraberry, Lower Spraberry, Dean, and Wolfcamp formations. These formations are correlative over the area but are lenticular in nature and vary in thickness, porosity, and permeability even over short distances. The general completion technique includes hydraulic fracturing and installation of sucker rod pumps. During 2012, W&T drilled 64 additional wells, which included one horizontal well. Cumulative field production through 2012 is approximately 2.8 MMBoe (17.1 Bcfe) from our wells. In 2013, W&T plans to drill 20 vertical wells and seven horizontal wells. Total proved reserves associated with our interest in the Spraberry field were 31.6 MMBoe (189.8 Bcfe) at December 31, 2012 and 28.1 MMBoe (168.5 Bcfe) at December 31, 2011.

The following presents historical information about our produced oil, NGLs and natural gas volumes from the Spraberry field for the year 2012 and from the acquisition date of May 11, 2011 to December 31, 2011.


	Year Ended December 31, 2012		May 11 - December 31, 2011
Net sales:
Oil (MBbls)		751		452
NGLs (MBbls)		103		60
Natural gas (MMcf)		376		214
Total oil equivalent (MBoe)		916		548
Total natural gas equivalent (MMcfe)		5,496		3,289
Total oil equivalent (Boe/day)		2,503		2,333
Total natural gas equivalent (Mcfe/day)		15,016		13,997

Average realized sales prices:
Oil ($/Bbl)	$	88.11	$	91.09
NGLs ($/Bbl)		36.94		51.70
Natural gas ($/Mcf)		2.50		3.05
Oil equivalent ($/Boe)		77.38		82.03
Natural gas equivalent ($/Mcfe)		12.90		13.67

Average production costs (1):
Oil equivalent ($/Boe)	$	18.92	$	13.62
Natural gas equivalent ($/Mcfe)		3.15		2.27

(1)	Includes lease operating expenses and gathering and transportation costs.


Volume measurements:
Boe – barrel of oil equivalent		Mcf – thousand cubic feet
MBbls – thousand barrels for crude oil, condensate or NGLs		MMcf – million cubic feet
MBoe – thousand barrels of oil equivalent		MMcfe – million cubic feet equivalent

Ship Shoal 349 Field (Mahogany).

Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, in 375 feet of water. The field area covers Ship Shoal blocks 349 and 359, with a single production platform on Ship Shoal block 349. Phillips Petroleum Company discovered the field in 1993. We initially acquired a 25% working interest in the field from BP Amoco in 1999. In 2003, we acquired an additional 34% working interest through a transaction with ConocoPhillips that increased our working interest to approximately 59%, and we became the operator of the field in December 2004. In early 2008, we acquired the remaining working interest from Apache Corporation and we now own a 100% working interest in this field. Cumulative field production through 2012 is approximately 31.2 MMBoe gross (187.0 Bcfe gross). This field is a sub-salt development with five productive horizons below salt at depths up to 17,000 feet. As of December 31, 2012, 25 wells have been drilled, 16 of which have been successful. In 2010, we developed a reservoir simulation model to determine the most optimal future development plan. As a result, in 2011, we drilled one development well and one exploration well. In 2012, a third well was drilled and completed as part of an ongoing drilling program and two additional wells were sidetracked. Total proved reserves associated with our interest in this field were 22.7 MMBoe (136.3 Bcfe) at December 31, 2012 and 20.3 MMBoe (121.7 Bcfe) at December 31, 2011.

The following presents historical information about our produced oil, NGLs and natural gas volumes from Ship Shoal 349 field over the past three fiscal years.


	Year Ended December 31,
	2012		2011		2010
Net sales:
Oil (MBbls)		960		445		657
NGLs (MBbls)		85		23		38
Natural gas (MMcf)		2,108		498		863
Total oil equivalent (MBoe)		1,397		551		838
Total natural gas equivalent (MMcfe)		8,380		3,305		5,030
Total oil equivalent (Boe/day)		3,816		1,509		2,297
Total natural gas equivalent (Mcfe/day)		22,896		9,055		13,782

Average realized sales prices:
Oil ($/Bbl)	$	102.55	$	101.30	$	73.20
NGLs ($/Bbl)		41.74		56.06		43.54
Natural gas ($/Mcf)		2.78		4.20		4.88
Oil equivalent ($/Boe)		77.24		87.97		64.33
Natural gas equivalent ($/Mcfe)		12.87		14.66		10.72

Average production costs (1):
Oil equivalent ($/Boe)	$	6.27	$	14.30	$	13.20
Natural gas equivalent ($/Mcfe)		1.05		2.38		2.20

(1)	Includes lease operating expenses and gathering and transportation costs.


Volume measurements:
Boe – barrel of oil equivalent		Mcf – thousand cubic feet
MBbls – thousand barrels for crude oil, condensate or NGLs		MMcf – million cubic feet
MBoe – thousand barrels of oil equivalent		MMcfe – million cubic feet equivalent

The following is a description of the remainder of our top 10 properties, measured by proved reserves at December 31, 2012, five of which are located on the conventional shelf and three are located in the deepwater. We do not believe that individually any of these properties are of major significance (each has proved reserves which comprise less than 15% of our total proved reserves, calculated on a natural gas equivalent basis).

Viosca Knoll 783 Field. (Viosca Knoll 783 Lease (Tahoe) and Viosca Knoll 784 Lease (SE Tahoe)) The Viosca Knoll 783 field is located off the coast of Louisiana, approximately 140 miles southeast of New Orleans, in 1,500 to 1,700 feet of water. The field area covers Viosca Knoll blocks 783 and 784, with subsea tiebacks to two platforms in Main Pass 252. Shell discovered the Tahoe prospect in 1984 and the SE Tahoe prospect in 1996. We acquired a 70% working interest in the Tahoe lease and a 100% working interest in the SE Tahoe lease from Shell in 2010. Cumulative field production through 2012 is approximately 31.2 MMBoe gross (187.0 Bcfe gross). The Tahoe prospect is a supra-salt (above the salt layer) development with two productive horizons at depths ranging to 10,300 feet. The SE Tahoe prospect is also a supra-salt development with one productive horizon at a depth of 9,325 feet. As of December 31, 2012, 16 wells have been drilled at the Tahoe prospect, eight of which have been successful and one successful well has been drilled at the SE Tahoe prospect. During December 2012, production from this field, net to our interest, averaged 336 Bbls of oil per day, 1,505 Bbls of NGLs per day and 26,240 Mcf of natural gas per day, for total production of 6,215 Boe per day (37,288 Mcfe per day).

Fairway Field (Fairway Properties). Fairway is comprised of Mobile Bay Area blocks 113 (Alabama State Lease #0531) and 132 (Alabama State Lease #0532) and located in 25 feet of water, approximately 35 miles south of Mobile, Alabama. We acquired our 64.3% working interest, along with operatorship in the Fairway field, from Shell in August 2011. The field was discovered in 1985 with Well 113 #1 (now called JA). Development drilling began in 1990 and was completed in 1991 with the addition of four wells, each drilled from separate surface locations. The five producing wells came on line in late 1991. As of December 31, 2012, six wells have been drilled, one of which was a replacement well. Cumulative field production through 2012 is approximately 112.5 MMBoe gross (674.9 Bcfe gross). This field is a Norphlet sand dune trend development with one producing horizon at an approximate depth of 21,300 feet. During December 2012, production from this field, net to our interest, averaged 17 Bbls of oil per day, 1,495 Bbls of NGLs per day and 20,779 Mcf of natural gas per day, for total production of 4,975 Boe per day (29,848 Mcfe per day).

Main Pass 108 Field. Main Pass 108 field consists of Main Pass blocks 107, 108 and 109. This field is located off the coast of Louisiana approximately 50 miles east of Venice in 50 feet of water. We acquired our working interests in these blocks, which range from 33% to 100%, in a transaction with Kerr-McGee Oil and Gas Corporation (“Kerr-McGee”). The field produces from a number of low relief, predominantly stratigraphically trapped sands. The productive interval ranges in age from Upper Miocene Big A through Middle Miocene Big Hum. As of December 31, 2012, 43 wells have been drilled in this field, 35 of which were successful. Cumulative field production through 2012 is approximately 41.9 MMBoe gross (251.6 Bcfe gross). One new well reached target depth in 2011 and began production in 2012. In addition, one workover was performed in 2012. During December 2012, production from this field, net to our interest, averaged 329 Bbls of oil per day, 437 Bbls of NGLs per day and 15,246 Mcf of natural gas per day, for total production of 3,306 Boe per day (19,838 Mcfe per day).

Mississippi Canyon 243 Field. (Matterhorn) Mississippi Canyon 243 field is located off the coast of Louisiana, approximately 100 miles southeast of New Orleans, in 2,552 feet of water. The field area covers Mississippi Canyon block 243, with a single floating, tension leg production platform on Mississippi Canyon block 243. Société Nationale Elf Aquitaine discovered the field in 2002. We acquired a 100% working interest in the field from Total E&P USA (“Total E&P”) in 2010. Cumulative field production through 2012 is approximately 22.0 MMBoe gross (131.8 Bcfe gross). This field is a supra-salt development with 17 productive horizons at depths ranging to 9,850 feet. As of December 31, 2012, 18 wells have been drilled, eight of which have been successful. During December 2012, production from this field, net to our interest, averaged 2,454 Bbls of oil per day, 282 Bbls of NGLs per day and 3,932 Mcf of natural gas per day, for total production of 3,391 Boe per day (20,347 Mcfe per day).

Viosca Knoll 823 Field. (Virgo) Viosca Knoll 823 field is located off the coast of Louisiana, approximately 125 miles southeast of New Orleans, in 1,014 feet of water. The field area covers Viosca Knoll block 823 and Viosca Knoll block 822, with a single fixed leg production platform on Viosca Knoll block 823. Total E&P discovered the field in 1997. We acquired a 64% working interest in the field from Total E&P in 2010. Cumulative field production through 2012 is approximately 20.0 MMBoe gross (120.5 Bcfe gross). This field is a supra-salt development with 17 productive horizons at depths ranging to 13,335 feet. As of December 31, 2012, 12 wells have been drilled, 10 of which have been successful. During December 2012, production from this field, net to our interest, averaged 292 Bbls of oil per day, 187 Bbls of NGLs per day and 6,182 Mcf of natural gas per day, for total production of 1,510 Boe per day (9,060 Mcfe per day).

High Island 22 Field. High Island 22 field consists of High Island blocks 21 and 22. The field is located approximately 10 miles off the Texas coastline in 36 feet of water. Two platforms, the “A” and the “B”, are located on block 22. We acquired a 100% working interest in the field from Kerr-McGee in 2006. The field produces from two major sands, the LH 20 and LH 24. The productive sands are Lower Miocene, Lent Hanseni in age. As of December 31, 2012, 12 wells have been drilled, eight of which have been successful. A recent field study resulted in certain reserves being classified as proved as of December 31, 2012, compared to reserves being classified as unproved in 2011. Cumulative field production through 2012 is approximately 30.0 MMBoe gross (179.9 Bcfe gross). During December 2012, production from this field, net to our interest, averaged one Bbl of oil per day, one Bbl of NGLs per day and 95 Mcf of natural gas per day, for total production of 18 Boe per day (109 Mcfe per day).

Main Pass 98 Field. Main Pass 98 field consists of Main Pass blocks 98 and 180. This field is located off the coast of Louisiana approximately 55 miles east of Venice in 91 feet of water. We acquired our 100% working interest in these blocks from NCX Co LLC in 2009. The field produces from low relief, predominantly stratigraphically trapped sands located between two merging, generally south dipping faults. The productive interval is Middle Miocene Bigenerina Humblei. Cumulative field production through 2012 is approximately 4.1 MMBoe gross (24.7 Bcfe gross). As of December 31, 2012, 11 wells have been drilled, seven of which have been successful. In 2012, no wells were drilled or recompleted and three workovers were performed. During December 2012, production from this field, net to our interest, averaged 106 Bbls of oil per day, 70 Bbls of NGLs per day and 2,171 Mcf of natural gas per day, for total production of 537 Boe per day (3,225 Mcfe per day).

East Cameron 321 Field. East Cameron 321 field is located approximately 97 miles off the Louisiana coastline in 225 feet of water. Two production facilities, the “A” and “B” platforms, are located on the block. This field has multiple sands that are productive in faulted, structural traps. These sands are Pleistocene Ang B in age. As of December 31, 2012, 75 wells have been drilled, 57 of which have been successful. Cumulative field production through 2012 is approximately 93.6 MMBoe gross (561.7 Bcfe gross). We own a 100% working interest in the field and are the operator. During December 2012, production from this field, net to our interest, averaged 1,279 Bbls of oil per day and 266 MMcf of natural gas per day, for total production of 1,324 Boe per day (7,942 Mcfe per day).

Proved Reserves

Our estimated proved reserves totaled 117.5 MMBoe (705.1 Bcfe) at December 31, 2012. The mix by product was 47% oil, 13% NGLs and 40% natural gas determined using the energy-equivalent ratio noted below. Our proved reserves were estimated by NSAI, our independent petroleum consultant.

Our proved reserves are summarized below. These reserve amounts are consistent with filings we make with other federal agencies.


	As of December 31, 2012
							Total Equivalent Reserves
Classification of Proved Reserves (1)	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Oil Equivalent (MBoe) (2)		Natural Gas Equivalent (MMcfe) (2)		% of Total Proved			PV-10 (3) (In millions)
Proved developed producing		24,673		8,906		173,906		62,563		375,380		53	%	$	1,664
Proved developed non-producing		10,663		2,051		69,535		24,303		145,819		21	%		777

Total proved developed		35,336		10,957		243,441		86,866		521,199		74	%		2,441
Proved undeveloped		19,490		4,220		41,614		30,646		183,874		26	%		379

Total proved		54,826		15,177		285,055		117,512		705,073		100	%	$	2,820


Volume measurements:
MBbls – thousand barrels for crude oil, condensate or NGLs		MMcf – million cubic feet
MBoe – thousand barrels of oil equivalent		MMcfe – million cubic feet equivalent

(1)

In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2012 were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the year end December 31, 2012. Prices were adjusted by lease for quality, transportation, fees, energy content and regional price differentials. For oil, the West Texas Intermediate posted price was used in the calculation and, after adjustments, a price of $98.13 per Bbl was used in computing the amounts above. For NGLs, a ratio was computed for each field of the NGLs realized price compared to the oil realized price. Then, this ratio was applied to the oil price using SEC guidance. The NGLs price of $47.30 per Bbl was used in computing the amounts above. For natural gas, the average Henry Hub spot price was used in the calculation and the adjusted price of $2.77 per Mcf was used in computing the amounts above. Such prices were held constant throughout the estimated lives of the reserves. Future production, development costs and ARO are based on year-end costs with no escalations.

(2)

Energy equivalents are determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent price for oil and NGLs may differ significantly.

(3)

We refer to PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our independent petroleum consultant using a discount rate of 10%. This amount includes projected revenues, estimated production costs and estimated future development costs and excludes ARO. We have also included PV-10 after ARO below. PV-10 after ARO includes the present value of ARO related to proved reserves using a 10% discount rate and no inflation of current costs. Neither PV-10 nor PV-10 after ARO are financial measures defined under generally accepted accounting principles (“GAAP”); therefore, the following table reconciles these amounts to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Management believes that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 and PV-10 after ARO are used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of pre-tax measures is valuable because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV-10 and PV-10 after ARO provide useful information to investors because they are widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 and PV-10 after ARO are not measures of financial or operating performance under GAAP, nor are they intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 and PV-10 after ARO should not be considered in isolation or as substitutes for the standardized measure of discounted future net cash flows as defined under GAAP.

The reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves is as follows (in millions):


	As of December 31, 2012
Present value of estimated future net revenues (PV-10)	$	2,820
Present value of estimated ARO, discounted at 10%		(328	)

PV-10 after ARO		2,492
Future income taxes, discounted at 10%		(646	)

Standardized measure of discounted future net cash flows	$	1,846

Changes in Proved Reserves

Our total proved reserves increased to 117.5 MMBoe (705.1 Bcfe) at December 31, 2012 from 116.9 MMBoe (701.1 Bcfe) at December 31, 2011, primarily as a result of extensions and discoveries of 15.7 MMBoe (94.5 Bcfe) due to our participation in the drilling of 25 successful exploratory wells (gross) and increases resulting from well completions and recompletions. The extensions and discoveries were primarily in the Yellow Rose Properties (11.6 MMBoe /69.5 Bcfe), the High Island 22 field (2.7 MMBoe/16.2 Bcfe) and the West Cameron 71 field (1.0 MMBoe/6.1 Bcfe). For the Yellow Rose Properties, the increase to proved reserves was due to 11 exploration wells being completed. In addition, there was a redetermination of reserves related to successful horizontal drilling and drilling using 40 acre spacing in certain areas. For the High Island 22 field, the increase in proved reserves was due to a recent field study that demonstrated that additional reserves could be recovered by drilling a replacement for a well that experienced a mechanical failure. The increase at the West Cameron 71 field was due to a successful exploration well. Estimated proved reserves also increased from the acquisition of Newfield Properties discussed in Item 1, Business, which added 7.0 MMBoe (42.0 Bcfe). Reserves decreased from revisions of previous estimates by 4.6 MMBoe (27.5 Bcfe) and by 0.4 MMBoe (2.2 Bcfe) from the sale of one field. Decreases due to production were 17.1 MMBoe (102.8 Bcfe). See Development of Proved Undeveloped Reserves below for a table reconciling the change in proved undeveloped reserves during 2012. See Financial Statements – Note 21 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for additional information.

Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

Our estimated proved reserve information as of December 31, 2012 included in this Form 10-K was prepared by our independent petroleum consultant, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The scope and results of their procedures are summarized in a letter included as an exhibit to this Form 10-K. The primary technical person at NSAI responsible for overseeing the preparation of the reserves estimates presented herein has B.S. and M.S. degrees in Civil Engineering and has been a Registered Professional Engineer in the State of Texas for 24 years and a member of the Society of Petroleum Engineers for over 28 years. He has over 35 years total experience in the oil and gas industry, with over 21 years of reservoir engineering experience. His areas of experience are the continental shelf and deepwater Gulf of Mexico, San Juan Basin, onshore and offshore Mexico, offshore Africa, and unconventional gas sources worldwide. NSAI has informed us that he meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.

We maintain an internal staff of reservoir engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates. Additionally, our senior management reviews any

significant changes to our proved reserves on a quarterly basis. Our Reservoir Engineering Manager has served in that capacity since 2006, after having served as a Staff Reservoir Engineer since joining the Company in 2004. Prior to joining the Company, he served as a Reservoir Engineer at Shell, then VP of Reservoir Engineering at Freeport-McMoRan Oil & Gas and later as Manager Acquisitions Engineering at Matrix Oil & Gas. He received a Bachelor of Science degree in Engineering Science from Iowa State University in 1972.

Reserve Technologies

Proved reserves are those quantities of oil and natural 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. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our independent petroleum consultant employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

•

the quality and quantity of available data and the engineering and geological interpretation of that data;

•

estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;

•

the accuracy of various mandated economic assumptions such as the future prices of oil and natural gas; and

•

the judgment of the persons preparing the estimates.

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.

Reporting of Natural Gas and Natural Gas Liquids

We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. We report all natural gas production information net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs. We convert Bbl to Mcfe using an energy-equivalent ratio of six Mcf to one Bbl of oil, condensate or NGLs. This energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas may differ substantially.

Development of Proved Undeveloped Reserves

Our proved undeveloped reserves (“PUDs”) were estimated by NSAI, our independent petroleum consultant. Future development costs associated with our PUDs at December 31, 2012 were estimated at $583.6 million.

Our PUDs by field as of December 31, 2012 and 2011 are as follows:


	December 31, 2012				December 31, 2011
	MMBoe		Bcfe		MMBoe		Bcfe
Ship Shoal 349 (Mahogany)		4.8		29.1		16.6		99.8
Mississippi Canyon 243		2.1		12.3		3.1		18.8
Viosca Knoll 823		1.4		8.6		1.4		8.2
Spraberry (Yellow Rose)		19.6		117.7		19.4		116.1
High Island 22		2.7		16.2		—		—

Total		30.6		183.9		40.5		242.9

The following table presents a reconciliation of our PUDs for 2012:


	Year 2012
	MMBoe			Bcfe
Proved undeveloped reserves – beginning of year		40.5			242.9
Reductions:
Ship Shoal 349 (Mahogany) – three wells drilled, two wells completed, reclassified to proved developed		(11.8	)		(70.8	)
Mississippi Canyon 243 – one well completed		(1.6	)		(9.8	)
Spraberry (Yellow Rose) – PUD wells reclassified and performance		(9.7	)		(58.0	)
Revisions due to pricing		(0.2	)		(0.9	)

Subtotal – reductions		(23.3	)		(139.5	)

Balance after reductions		17.2			103.4


Additions:
High Island 22 – reclassification from unproved due to study		2.7			16.2
Spraberry (Yellow Rose) – PUD well additions		10.0			59.6
Other changes		0.7			4.7

Subtotal – additions		13.4			80.5

Proved undeveloped reserves – end of year		30.6			183.9


Volume measurements:
MMBoe – million barrels of oil equivalent		Bcfe – billion cubic feet equivalent

During 2012, we drilled numerous development wells that converted PUDs to proved developed reserves (“PDs”) and spent $263.6 million on development of PUDs during 2012. Activity in 2012 allowed conversion of approximately 50% of the PUDs existing at December 31, 2011 to proved developed reserves as of December 31, 2012. At our Ship Shoal 349/359 (Mahogany) field, we completed two wells, (SS 359 A5 ST and SS 359 A13). As of December 31, 2012, we were in the process of completing the SS 359 A9 ST well, which moved additional reserves from PUDs to PDs. In 2013, we plan to drill the SS 359 A14 well and A15 well. This drilling program has resulted in the reclassification of a substantial portion of the PUDs to PDs in the Mahogany field. The PUDs at our Mississippi Canyon 243 field and Viosca Knoll 823 fields were obtained through acquisitions in 2010. We completed one well at Mississippi Canyon 243 (MC 243 A4 ST) in 2012 and are currently drilling another development well (MC 243 A2 ST BP1). Development of the Mississippi Canyon 243 field and Viosca Knoll 823 field is expected to continue into 2014.

In May 2011, we acquired the Yellow Rose Properties, which contributed to a significant increase in PUDs in 2011. In this field, we completed 27 development wells and nine exploration wells from the acquisition date of May 11, 2011 to December 31, 2011. In 2012, we completed 53 development wells and 11 exploration wells. One of the wells completed was a horizontal well and two other horizontal wells reached target depth in 2012, which proved the concept and allowed additional horizontal PUD locations to be booked. Additionally, wells completed in 2011 and 2012 proved that the concept of down spacing to 40-acres was viable in a portion of the field, allowing the conversion of certain unproven locations to PUDs in 2012. In 2013, we expect to drill approximately 26 development wells and one exploration well, comprised of seven horizontal wells and 20 vertical wells. See Business under Part I, Item 1, Our Fields in Item 2 above and Financial Statements – Note 2 – Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information on the Yellow Rose Properties.

In the High Island 22 field, a recent field study demonstrated that additional reserves could be recovered by drilling a replacement for a well that experienced a mechanical failure. This allowed unproved reserves in 2011 to be reclassified as proved reserves as of December 31, 2012.

We believe that we will be able to develop all of the reserves classified as PUDs at December 31, 2012 within five years from the date such reserves were recorded. Our capital budget for 2013 is up 6% from our 2012 capital budget, with 37% dedicated to development activities, split 43% offshore and 57% onshore. The capital allocated to our development activities will assist us in converting the PUDs to proved developed reserves.

Acreage

The following summarizes our leasehold at December 31, 2012. Deepwater refers to acreage in over 500 feet of water.


	Developed Acreage				Undeveloped Acreage				Total Acreage
	Gross		Net		Gross		Net		Gross		Net
Shelf		586,624		356,552		124,137		124,137		710,761		480,689
Deepwater		124,083		65,831		357,120		240,406		481,203		306,237

Total Offshore		710,707		422,383		481,257		364,543		1,191,964		786,926
Onshore		24,978		20,540		196,055		163,824		221,033		184,364

Total		735,685		442,923		677,312		528,367		1,412,997		971,290

Approximately 54% of our total net offshore acreage is developed and approximately 11% of our total net onshore acreage is developed. We have the right to propose future exploration and development projects on the majority of our acreage.

For the offshore undeveloped leasehold, 48,689 net acres of the total 364,543 net undeveloped offshore acres (13%) could expire in 2013, 95,393 net acres (26%) could expire in 2014, 57,166 net acres (16%) could expire in 2015, 31,968 net acres (9%) could expire in 2016, and 131,327 net acres (36%) could expire in 2017 and beyond. For the onshore undeveloped leasehold, our rights to approximately 148,318 net acres of the total 163,824 net undeveloped onshore acres (91%) could expire in 2013, 5,463 net acres (3%) could expire in 2014, 10,038 net acres (6%) could expire in 2015, and five net acres could expire thereafter. Of the undeveloped onshore leasehold, there are 138,235 net acres that can be extended by drilling two additional wells in 2013 and further extended by additional operations or production in future years. In making decisions regarding drilling and operations activity for 2013, we give consideration to undeveloped leasehold that may expire in the near term in order that we might retain the opportunity to extend such acreage.

Our net offshore acreage increased 273,645 net acres (53%) from December 31, 2011 and our net onshore acreage increased 10,930 net acres (6%) from December 31, 2011. The increase in our net offshore acreage was primarily attributable to the Newfield Properties acquisition and offshore property interests acquired through purchase from the government. This increase was partially offset due to certain offshore leases that terminated and the sale of our interest at South Timbalier 41. The increase in our net onshore acreage is primarily attributable to additional leasehold interests acquired in Texas.

Production

For the years 2012, 2011 and 2010, our net daily production averaged 280.9 MMcfe, 278.2 MMcfe and 238.4 MMcfe, respectively. Production increased in 2012 from 2011 primarily due to acquisitions completed in 2012 and 2011 and increases in the Ship Shoal 349 field attributable to development activities, partially offset by decreases related to storms, pipeline shutdowns and natural reservoir declines. Production increased in 2011 from 2010 primarily due to acquisitions completed in 2011 and 2010 and the resumption of operations in certain fields that had been shut down from June 2010 to March 2011 due to pipeline outages.

Production History

The following presents historical information about our produced oil, NGLs and natural gas volumes from all of our producing fields over the past three fiscal years.


	Year Ended December 31,
	2012		2011		2010
Net sales:
Oil (MBbls)		6,033		6,073		5,863
NGLs (MBbls)		2,129		1,892		1,190
Natural gas (MMcf)		53,825		53,743		44,713
Total oil equivalent (MBoe)		17,133		16,921		14,505
Total natural gas equivalent (MMcfe)		102,800		101,528		87,032


Volume measurements:
MBbls – thousand barrels for crude oil, condensate or NGLs		MMcf – million cubic feet
MBoe – thousand barrels of oil equivalent		MMcfe – million cubic feet equivalent

Refer to the descriptions of our 10 largest fields reported earlier in this Item 2, Properties, for historical information about our produced volumes from our Spraberry field (Yellow Rose Properties) and Ship Shoal 349 field (Mahogany) over the past three fiscal years, each of which have proved reserves exceeding 15% of our total proved reserves. Also refer to Selected Financial Data – Historical Reserve and Operating Information under Part II, Item 6 of this Form 10-K for additional historical operating data, including average realized sale prices and production costs.

Productive Wells

The following presents our ownership interest at December 31, 2012 in our productive oil and natural gas wells. A net well represents our fractional working interest of a gross well in which we own less than all of the working interest.

Offshore Wells


	Oil Wells				Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Operated		83		72		87		69		170		141
Non-operated		43		18		40		11		83		29

		126		90		127		80		253		170

Onshore Wells


	Oil Wells				Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Operated		174		173		2		2		176		175
Non-operated		9		3		—		—		9		3

		183		176		2		2		185		178

All Productive Wells


	Oil Wells (1)				Gas Wells (1)				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Operated		257		245		89		71		346		316
Non-operated		52		21		40		11		92		32

		309		266		129		82		438		348

(1)	Includes seven gross (5.0 net) oil wells and eight gross (4.9 net) gas wells with multiple completions.

Drilling Activity

As presented in the tables below, our drilling activity increased in 2012 compared to 2011, and also increased in 2011 compared to 2010. Our onshore drilling activity increased after our acquisition of the Yellow Rose Properties in May 2011 and additional leasehold interests acquired in both West and East Texas.

The tables below are based on the SEC’s criteria of completion or abandonment to determine productive wells drilled.

Development Drilling

The following table sets forth information relating to our development wells drilled over the past three years.


	Year Ended December 31,
	2012		2011		2010
Gross Wells:
Productive:
Offshore		3		5		1
Onshore		53		27		—
Non-productive:
Offshore		—		—		—
Onshore		—		—		—

		56		32		1


Net Wells:
Productive:
Offshore		3.0		4.5		0.1
Onshore		52.8		27.0		—
Non-productive:
Offshore		—		—		—
Onshore		—		—		—

		55.8		31.5		0.1

Our success rates related to our gross development wells drilled during 2012, 2011 and 2010 were 100% each year.

Exploration Drilling

The following table sets forth information relating to our exploration drilling over the past three years.


	Year Ended December 31,
	2012		2011		2010
Gross Wells:
Productive:
Offshore		1		3		5
Onshore		24		12		—
Non-productive:
Offshore		1		—		1
Onshore		—		1		2

		26		16		8


Net Wells:
Productive:
Offshore		0.3		2.4		3.6
Onshore		20.8		7.6		—
Non-productive:
Offshore		0.4		—		1.0
Onshore		—		0.7		0.7

		21.5		10.7		5.3

Our success rates related to our gross exploration wells drilled during 2012, 2011 and 2010 were 96%, 94% and 63%, respectively.

Recent Drilling Activity

The following table sets forth 2013 drilling activity to February 15, 2013.


	January 1, 2013 to February 15, 2013
	Development		Exploration
Gross Wells:
Productive:
Offshore		—		—
Onshore		8		2
Non-productive:
Offshore		—		1
Onshore		—		—

		8		3


Net Wells:
Productive:
Offshore		—		—
Onshore		8.0		1.9
Non-productive:
Offshore		—		1.0
Onshore		—		—

		8.0		2.9

As of February 15, 2013, we were in the process of drilling and/or completing on a gross well basis one offshore development well, three offshore exploration wells, nine onshore exploration wells and two onshore development wells.

Capital Expenditures

The level of our investment in oil and gas properties changes from time to time depending on numerous factors, including the prices of oil, NGLs and natural gas, acquisition opportunities and the results of our exploration and development activities. For 2012, our capital expenditures for oil and natural gas properties and equipment of $684.9 million included $205.6 million for acquisitions, $137.1 million for exploration activities, $310.2 million for development activities and $32.0 million for seismic, capitalized interest and other leasehold costs. See Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this Form 10-K for additional information.

Item 3.

Legal Proceedings

Federal Grand Jury Investigation. The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the EPA conducted a federal grand jury investigation beginning in late 2010 of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms in the Gulf of Mexico in 2009. In December 2012, an agreement was reached that resolves these environmental violations and the agreement was approved by the federal district court in January 2013. Under the agreement, the Company on January 3, 2013 (i) pled guilty to one felony count under the Clean Water Act for altering monthly produced water discharge samples for the Ewing Banks 910 platform in 2009 and one misdemeanor count under the Clean Water Act for negligently discharging a small amount of oil from the same platform in November 2009 and (ii) paid a $0.7 million fine and $0.3 million for community service and (iii) entered into an environmental compliance program subject to a third-party audit. Under the agreement, the Company was placed on a three-year term of probation. The probation terms require that the Company: a) commit no further criminal violations, b) pay in full amounts pursuant to the agreement, c) comply with an Environmental Compliance Plan during the probation period, and d) take no adverse action against personnel who cooperated in the investigation. The agreement further stipulates that the Government will not seek any further criminal charges against the Company in this matter.

Cameron Parish Louisiana Claim. Since 2009, certain Cameron Parish landowners have filed suits in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and Tracy W. Krohn as well as several other defendants unrelated to us. In their lawsuits, plaintiffs alleged that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and they are seeking compensatory and punitive damages. During 2012, we settled claims with certain landowners and paid $10.0 million. We assessed the remaining claims to be probable and have accrued $1.3 million in our contingent liabilities as of December 31, 2012. However, we cannot state with certainty that our estimates of additional exposure are accurate concerning this matter.

Qui Tam Litigation. On September 21, 2012, we were served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of a Company contractor. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494, was filed in the United States District Court for the Eastern District of Louisiana, against the Company and three other working interest owners related to claims associated with three of the Company’s operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. The complaint was originally filed in 2010 but kept under confidential seal in order for the federal government to decide if it wished to intervene and take over the prosecution of the qui tam action. The government declined to intervene in this suit and the complaint was unsealed and made public in June 2012, thereby giving the plaintiff the opportunity to pursue the claims on behalf of the government.

benefits under the applicable leases. The alleged environmental violations include allegations of discharges of relatively small amounts of oil into the Gulf of Mexico, the failure to report and record such discharges, and falsification of certain produced water samples and related reports required under federal law. The events are alleged to have occurred in 2009. These are largely the same allegations involved in the federal grand jury investigation described above. We have filed a motion to dismiss the claim. The plaintiff dismissed his claims against the three other working interest owners after they filed motions to dismiss. The plaintiff conceded that certain of his claims should be dismissed in his reply to the Company’s motion to dismiss. The motion remains pending before the court.

The Company intends to vigorously defend the claims made in this lawsuit. At this early stage of the lawsuit, the Company has determined that although the likelihood of an adverse outcome is reasonably possible, the range of potential loss cannot yet be estimated, and accordingly, no accrual has been made.

Insurance Claims. During the fourth quarter of 2012, underwriters of our excess liability policies (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company; XL Specialty Insurance Company and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that such policies do not cover removal of wreck and debris claims arising from Hurricane Ike that occurred in 2008. The court consolidated the various suits filed by underwriters. We have not yet filed any claim under such excess policies, but we anticipate that such claims may reach $50.0 million in aggregate. In January 2013, the Company filed a motion for summary judgment seeking the court’s determination that such excess policies do in fact provide coverage for such removal of wreck and debris claims. The motion for summary judgment is pending. If successful, we expect to receive reimbursement for these costs once costs have been incurred and claims submitted. Costs that have been incurred in connection with potential claims have been recorded in Oil and natural gas properties and equipment on the Consolidated Balance Sheet. Any recoveries from claims made on these policies related to this issue will be recorded as reductions in this line item.

Proceedings by Government Authorities. During 2012, we received notices of non-compliance from various government authorities that were related to various incidences occurring in 2012 and in prior years. Excluding the $1.0 million in payments described above, cumulative payments of fines during 2012 were less than $0.1 million. There are currently no fines outstanding that have not been paid and management has not been informed of any potential fines relating to recently completed inspections at this time.

Other Litigation. From time to time, we are party to other litigation or legal and administrative proceedings that we consider to be a part of the ordinary course of our business. Except for the matters noted above, we are not involved in any legal proceedings nor are we party to any pending or threatened claims that could, individually or in the aggregate, reasonably be expected to have a material adverse effect on our financial condition, cash flow or results of operations.

Executive Officers of the Registrant

The following lists our executive officers:


Name	Age (1)		Position
Tracy W. Krohn		58	Founder, Chairman, Director and Chief Executive Officer
Jamie L. Vazquez		52	President
John D. Gibbons		59	Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Thomas P. Murphy		50	Senior Vice President and Chief Operations Officer
Stephen L. Schroeder		50	Senior Vice President and Chief Technical Officer
Thomas F. Getten		65	Vice President, General Counsel and Corporate Secretary

(1)	Ages as of February 23, 2013.

Tracy W. Krohn has served as Chief Executive Officer since he founded the Company in 1983 and as Chairman since 2004. He also served as President of the Company until September 2008. During 1996 to 1997, Mr. Krohn was Chairman and Chief Executive Officer of Aviara Energy Corporation. Prior to founding the Company, from 1982 to 1983, Mr. Krohn was a senior engineer with Taylor Energy, and he began his career as a petroleum engineer and offshore drilling supervisor with Mobil Oil Corporation.

Jamie L. Vazquez joined the Company in 1998 as Manager of Land and in 2003 she was named Vice President of Land. In September 2008, Ms. Vazquez was appointed President of the Company. Prior to joining the Company, Ms. Vazquez was with CNG Producing Company for 17 years, holding positions of increasing responsibility ending as Manager, Land/Business Development Gulf of Mexico.

John D. Gibbons joined the Company in February 2007 as Senior Vice President and Chief Financial Officer. In September 2007, he assumed the additional position of Chief Accounting Officer. Prior to joining the Company, Mr. Gibbons was Senior Vice President and Chief Financial Officer of Westlake Chemical Corporation from March 2006 to February 2007. Prior to joining Westlake, Mr. Gibbons was with Valero Energy Corporation for 23 years, holding positions of increasing responsibility ending as Executive Vice President and Chief Financial Officer.

Thomas P. Murphy joined the Company in June 2012 as Senior Vice President and Chief Operations Officer. From 2009 to 2012, Mr. Murphy worked at Woodside Energy USA Inc. as Vice President Engineering and Operations. From 2008 to 2009 he worked for PetroQuest Energy, Inc. as Vice President Engineering. From 2000 to 2008, Mr. Murphy worked for Devon Energy Corporation in a variety of positions, including Gulf of Mexico Deep-Water Development Supervisor, New Business Development Supervisor and culminating in his position as Sr. Exploration Advisor.

Stephen L. Schroeder joined the Company in 1998 and served as Production Manager from 1999 until 2005. In 2005, Mr. Schroeder was named Vice President of Production and in July 2006 he was named Senior Vice President and Chief Operating Officer. In June, 2012, Mr. Schroeder was named Senior Vice President and Chief Technical Officer. Prior to joining the Company, Mr. Schroeder was with Exxon USA for 12 years holding positions of increasing responsibility, ending with Offshore Division Reservoir Engineer.

Thomas F. Getten joined the Company in July 2006 as Vice President, General Counsel and Assistant Secretary. In December 2011, Mr. Getten was appointed to the position of Corporate Secretary. Prior to joining the Company, Mr. Getten served as a partner with King, LeBlanc & Bland, P.L.L.C., a New Orleans law firm, since February 2001. From 1996 to December 2000, Mr. Getten served as Vice President, Secretary and General Counsel of Forcenergy Inc until its merger into Forest Oil Corporation.

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

Our common stock is listed and principally traded on the NYSE under the symbol “WTI.” The following table sets forth the high and low sales price of our common stock as reported on the NYSE.


	High		Low
2012
First Quarter	$	26.83	$	20.24
Second Quarter		21.56		13.31
Third Quarter		21.01		14.72
Fourth Quarter		19.35		15.54
2011
First Quarter		26.12		17.51
Second Quarter		28.79		21.09
Third Quarter		29.27		13.74
Fourth Quarter		22.86		11.87

As of February 25, 2013, there were 198 registered holders of our common stock.

Dividends

Under the Credit Agreement, we are allowed to pay annual dividends up to $60.0 million per year if we are not in default. In December 2012, we were granted a one-time waiver which allowed for cash dividends of up to $85.0 million during 2012. In addition, the indenture governing our 8.50% Senior Notes due in 2019 (the “8.50% Senior Notes”) contains restrictions on the payment of dividends unless we meet certain restricted payment tests. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 and Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for more information regarding our Credit Agreement and the indenture governing the 8.50% Senior Notes.

The following reflects the frequency and amounts of all cash dividends declared during the two most recent fiscal years (in thousands, except per share data):


	Aggregate Dividends on Common Stock		Dividends per Share of Common Stock
2012
First Quarter	$	5,948	$	0.08
Second Quarter		5,950		0.08
Third Quarter		5,950		0.08
Fourth Quarter (1)		64,984		0.87
2011
First Quarter		2,979		0.04
Second Quarter		2,979		0.04
Third Quarter		2,979		0.04
Fourth Quarter (2)		49,819		0.67

(1)	Includes a regular dividend of $6.0 million ($0.08 per common share) and two special cash dividends of $34.9 million ($0.47 per common share) and $24.1 million ($0.32 per common share).

(2)	Includes a regular dividend of $3.0 million ($0.04 per common share) and a special cash dividend of $46.9 million ($0.63 per common share).

With the exception of special cash dividends, we currently expect that comparable cash dividends will continue to be paid in the future, subject to periodic reviews of the Company’s performance by our board of directors and applicable debt agreement restrictions. On February 26, 2013, our board of directors declared a cash dividend of $0.08 per common share, payable on March 29, 2013 to shareholders of record on March 15, 2013.

Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 in our common stock and the reinvestment of all dividends thereafter. The information contained in the graph below is furnished and not filed, and is not incorporated by reference into any document that incorporates this Annual Report on Form 10-K by reference.

LOGO

Our peer group is comprised of Apache Corporation, ATP Oil & Gas Corp., Bill Barrett Corp., Cabot Oil & Gas Corp., Comstock Resources, Inc., Energy XXI (Bermuda) Limited, Forest Oil Corp., McMoRan Exploration Co., Newfield Exploration Co., SM Energy Co., SandRidge Energy, Inc., Stone Energy Corp., and Swift Energy Company.

Securities Authorized for Issuance Under Equity Compensation Plans

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K. For descriptions of the plans and additional information, see Financial Statements – Note 10 –Incentive Compensation Plan and Note 11– Share-Based and Cash-Based Incentive Compensation in Part II, Item 8 of this Form 10-K.

Issuer Purchases of Equity Securities

For the year 2012, we did not purchase any of our equity securities.

The following table sets forth information about restricted stock units delivered by employees during the quarter ended December 31, 2012 to satisfy tax withholding obligations on the vesting of restricted stock units.

Period

Total
Number of
Restricted
Stock Units
Delivered

Average
Price per
Restricted
Stock Unit

Total Number of
Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs

Maximum
Number (or
Approximate
Dollar Value) of
Shares that May
Yet Be
Purchased
Under the Plans
or Programs

October 1, 2012 – October 31, 2012

N/A

November 1, 2012 – November 30, 2012

N/A

December 1, 2012 – December 31, 2012

319,403

16.68

N/A

Item 6.

Selected Financial Data

SELECTED HISTORICAL FINANCIAL INFORMATION

The selected historical financial information set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 and with Financial Statements in Part II, Item 8 in this Form 10-K.


	Year Ended December 31,
	2012 (1)		2011 (2)			2010 (3)			2009			2008
	(Dollars in thousands, except per share data)
Consolidated Statement of Income (Loss) Information:
Revenues:
Oil	$	629,548	$	643,222		$	453,435		$	365,411		$	622,388
NGLs		84,637		105,559			51,931			35,247			65,709
Natural gas		158,390		221,194			203,533			204,758			527,352
Other (4)		1,916		1,072			(3,116	)		5,580			160

Total revenues (5)		874,491		971,047			705,783			610,996			1,215,609
Operating costs and expenses:
Lease operating expenses (6)		232,260		219,206			169,670			203,922			229,747
Production taxes		5,840		4,275			1,194			1,544			8,827
Gathering and transportation		14,878		16,920			16,484			13,619			15,957
Depreciation, depletion and amortization		336,177		299,015			268,415			308,076			482,464
Asset retirement obligation accretion		20,055		29,771			25,685			34,461			39,312
Impairment of oil and natural gas properties (7)		—		—			—			218,871			1,182,758
General and administrative expenses		82,017		74,296			53,290			42,990			47,225
Derivative (gain) loss		13,954		(1,896	)		4,256			7,372			16,464

Total costs and expenses		705,181		641,587			538,994			830,855			2,022,754

Operating income (loss)		169,310		329,460			166,789			(219,859	)		(807,145	)
Interest expense, net of amounts capitalized		49,994		42,516			37,706			40,087			34,709
Loss on extinguishment of debt (8)		—		22,694			—			2,926			—
Other income (9)		215		84			710			842			13,372

Income (loss) before income tax expense (benefit)		119,531		264,334			129,793			(262,030	)		(828,482	)
Income tax expense (benefit)		47,547		91,517			11,901			(74,111	)		(269,663	)

Net income (loss)	$	71,984	$	172,817		$	117,892		$	(187,919	)	$	(558,819	)

Earnings (loss) per common share
Basic and diluted	$	0.95	$	2.29		$	1.58		$	(2.51	)	$	(7.36	)
Dividends on common stock (10)		82,832		58,756			59,609			9,158			27,713
Cash dividends per common share (10)		1.11		0.79			0.80			0.12			0.36

Consolidated Cash Flow Information:
Net cash provided by operating activities	$	385,137	$	521,478		$	464,772		$	156,266		$	882,496
Capital expenditures – oil and natural gas properties		684,863		719,026			415,653			276,134			774,879


	December 31,
	2012		2011		2010		2009		2008
	(Dollars in thousands)
Consolidated Balance Sheet Information:
Cash and cash equivalents	$	12,245	$	4,512	$	28,655	$	38,187	$	357,552
Total assets		2,348,987		1,868,925		1,424,094		1,326,833		2,056,186
Long-term debt		1,087,611		717,000		450,000		450,000		653,172
Shareholders’ equity		541,187		544,574		421,743		358,950		572,227

(1)	In the fourth quarter of 2012, we acquired the Newfield Properties from Newfield.

(2)	In the second quarter of 2011, we acquired the Yellow Rose Properties from Opal and, in the third quarter of 2011, we acquired the Fairway Properties from Shell.

(3)	In the second quarter of 2010, we acquired certain properties from Total E&P and, in the fourth quarter of 2010, we acquired certain properties from Shell.

(4)	Included in other revenues for 2010 is a reduction of $4.7 million due to a disallowance by the ONRR of royalty relief for transportation of deepwater production through our subsea pipeline system that was originally recorded in 2009. We are contesting this ONRR adjustment.

(5)	Included in total revenues for 2010 is $24.9 million related to the recoupment of royalties paid to the ONRR in prior periods based on price thresholds that were believed to limit the availability of royalty relief on certain properties subject to the OCS Deepwater Relief Act of 1995.

(6)

Included in lease operating expenses are net charges to expense for hurricane-related repairs netted with insurance reimbursements. For the years 2010, 2009 and 2008, the impact to lease operating expenses attributable to net hurricane – related expenses/reimbursements were $11.7 million decrease, $18.4 million increase and $17.7 million increase, respectively. There was minimal impact to lease operating expenses in the other years presented.

(7)	The carrying amount of our oil and natural gas properties was written down by $218.9 million in 2009 and $1.2 billion in 2008 through the application of the full cost ceiling limitation due to lower oil and natural gas prices. No such write downs were required during the other years presented.

(8)

In 2011, we expensed repurchase premiums, deferred financing costs and other costs totaling $22.0 million related to the repurchase of $450.0 million in aggregate principal amount of our 8.25% Senior Notes due 2014 (the “8.25% Senior Notes”) and expensed $0.7 million of deferred financing costs related to replacement of our revolving bank credit facility. In 2009, we expensed $2.9 million of deferred financing costs related to the early repayment of our previously outstanding term loan facility (“Tranche B”).

(9)	In 2012, other income consisted primarily of gain from the sale of interest in an airplane. Amounts reported in all other periods presented consisted primarily of interest income.

(10)	The years 2012, 2011, 2010, and 2008 included special dividends of $59.0 million ($0.79 per share), $46.9 million ($0.63 per share), $49.2 million ($0.66 per share), and $20.8 million ($0.39 per share), respectively. The year 2009 did not include a special dividend.

HISTORICAL RESERVE AND OPERATING INFORMATION

The following presents summary information regarding our estimated net proved oil and natural gas reserves and our historical operating data for the years shown below. All calculations of estimated proved reserves have been made in accordance with the rules and regulations of the SEC in effect for that time period. For additional information regarding our estimated proved reserves, please read Business under Part I, Item 1 and Properties under Part I, Item 2 of the Form 10-K. The selected historical operating data set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and with Financial Statements under Part II, Item 8 in this Form 10-K.


	December 31,
	2012			2011			2010			2009			2008
Reserve Data:
Estimated net proved reserves (1)(2):
Oil (MMBbls)		54.8			51.4			34.0			31.2			40.0
NGLs (MMBbls)		15.2			17.1			4.2			3.0			3.9
Natural gas (Bcf)		285.1			289.7			256.3			165.8			227.9
Total oil equivalent (MMBoe)		117.5			116.9			80.9			61.8			81.9
Total natural gas equivalent (Bcfe)		705.1			701.1			485.4			371.0			491.1

Proved developed producing (Bcfe)		375.4			325.8			236.6			162.5			148.6
Proved developed non-producing (Bcfe) (3)		145.8			132.4			154.7			121.0			185.5

Total proved developed (Bcfe)		521.2			458.2			391.3			283.5			334.1

Proved undeveloped (Bcfe)		183.9			242.9			94.1			87.5			157.0
Total proved developed reserves as % of proved reserves		73.9	%		65.4	%		80.6	%		76.4	%		68.0	%

Reserve additions (reductions) (Bcfe):
Revisions (4)		(27.5	)		51.1			20.2			(25.4	)		(157.5	)
Extensions and discoveries		94.5			32.0			29.2			23.4			47.2
Purchases of minerals in place		42.0			234.1			152.0			0.7			60.5
Sales of minerals in place		(2.2	)		—			—			(24.0	)		—
Production		(102.8	)		(101.5	)		(87.0	)		(94.8	)		(97.9	)

Net reserve additions (reductions)		4.0			215.7			114.4			(120.1	)		(147.7	)

(1)

Estimated net proved reserves as of December 31, 2012, 2011, 2010 and 2009 are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December of the respective year in accordance with SEC guidelines. Estimated reserves as of December 31, 2008 are based on end-of-period commodity prices in accordance with the previous SEC guidelines in effect on such dates.

(2)

Energy equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy equivalent prices for oil, NGLs and natural gas may differ significantly.

(3)

Approximately 29.6 Bcfe of reserves were shut-in at December 31, 2010 due to two pipeline outages impacting several fields, including our Main Pass 108 field. Approximately 1.7 Bcfe and 53.9 Bcfe of reserves were shut-in at December 31, 2009 and 2008, respectively, because of damage caused by Hurricane Ike in September 2008.

(4)

Revisions for 2009 included decreases attributable to the changes in reserve reporting requirements for oil and natural gas companies enacted by the SEC, which became effective for us on December 31, 2009. The revised rules resulted in the removal of 23.2 Bcfe of proved undeveloped reserves associated with two of our fields for which our plan of development was not within five years from when the reserves were initially recorded.


Volume measurements:
Bcf – billion cubic feet		MMBbls – million barrels for crude oil, condensate or NGLs
Bcfe – billion cubic feet equivalent		MMBoe – million barrels of oil equivalent


	Year Ended December 31,
	2012		2011		2010		2009		2008
Operating Data:
Net sales:
Oil (MBbls)		6,033		6,073		5,863		6,095		5,886
NGLs (MBbls)		2,129		1,892		1,190		1,103		1,084
Oil and NGLs (MBbls)		8,163		7,964		7,053		7,198		6,970
Natural gas (MMcf)		53,825		53,743		44,713		51,621		56,072
Total oil equivalent (MBoe)		17,133		16,921		14,505		15,801		16,315
Total natural gas equivalent (MMcfe)		102,800		101,528		87,032		94,806		97,892

Average daily equivalent sales (Boe/day)		46,813		46,360		39,741		43,290		44,577
Average daily equivalent sales (Mcfe/day)		280,875		278,158		238,445		259,741		267,465

Average realized sales prices (Unhedged):
Oil ($/Bbl)	$	104.35	$	105.92	$	77.33	$	59.96	$	105.74
NGLs ($/Bbl)		39.75		55.81		43.65		31.96		60.62
Oil and NGLs ($/Bbl)		87.50		94.02		71.65		55.67		98.72
Natural gas ($/Mcf)		2.94		4.12		4.55		3.97		9.40
Oil equivalent ($/Boe)		50.93		57.32		48.87		38.32		74.50
Natural gas equivalent ($/Mcfe)		8.49		9.55		8.15		6.39		12.42

Average realized sales prices (Hedged) (1):
Oil ($/Bbl)		103.08	$	104.30	$	77.05	$	59.96	$	100.94
NGLs ($/Bbl)		39.75		55.81		43.65		31.96		60.62
Oil and NGLs ($/Bbl)		86.56		92.78		71.42		55.67		94.67
Natural gas ($/Mcf)		2.94		4.12		4.71		3.96		9.42
Oil equivalent ($/Boe)		50.48		56.74		49.25		38.30		72.82
Natural gas equivalent ($/Mcfe)		8.41		9.46		8.21		6.38		12.14

Average per Mcfe ($/Mcfe):
Lease operating expenses	$	2.26	$	2.16	$	1.95	$	2.15	$	2.35
Gathering and transportation costs		0.14		0.17		0.19		0.14		0.16

Production costs		2.40		2.33		2.14		2.29		2.51
Production taxes		0.06		0.04		0.01		0.02		0.09
Depreciation, depletion, amortization and accretion		3.47		3.24		3.38		3.61		5.33
General and administrative expenses		0.80		0.73		0.61		0.45		0.48

	$	6.73	$	6.34	$	6.14	$	6.37	$	8.41

Total number of wells drilled (gross):
Offshore		5		8		7		13		25
Onshore		77		40		2		—		—
Total number of productive wells drilled (gross):
Offshore		4		8		6		10		19
Onshore		77		39		—		—		—

(1)	Data for all years presented includes the effects of realized gains and losses on commodity derivative contracts, none of which qualified for hedge accounting.


Volume measurements:
Bbl – barrel		Mcf – thousand cubic feet
Boe – barrel of oil equivalent		MMcf – million cubic feet
MBbls – thousand barrels for crude oil, condensate or NGLs		MMcfe – million cubic feet equivalent
MBoe – thousand barrels of oil equivalent

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with Financial Statements under Part II, Item 8 of this Form 10-K. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K.

Overview

We are an independent oil and natural gas producer focused primarily in the Gulf of Mexico and Texas. We have grown through exploration, development and acquisitions and currently hold working interests in approximately 72 offshore fields (69 producing and three capable of producing) in federal and state waters. During 2011, we expanded onshore into West Texas and East Texas through an acquisition and acquiring interests in leasehold acreage. We have interests in offshore leases covering approximately 1.2 million gross acres (0.8 million net acres) spanning primarily across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama and 0.2 million gross acres (0.2 million net acres) onshore substantially all in Texas. We operate wells accounting for approximately 84% of our average daily production. We own interests in approximately 211 offshore structures, 144 of which are located in fields that we operate.

In managing our business, we are concerned primarily with maximizing return on shareholders’ equity. To accomplish this primary goal, we focus on increasing production and reserves at a profit. We strive to grow our reserves and production through acquisitions and our drilling programs. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.

In October 2012, we acquired from Newfield certain oil and gas leasehold interests. The properties consisted of leases covering 78 federal offshore blocks on approximately 432,700 gross acres (416,000 gross acres and 268,000 net acres excluding over-riding interests), comprised of 65 blocks in the deepwater, six of which are producing, 10 blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 MMBoe (42.0 Bcfe), comprised of approximately 61% natural gas, 36% oil and 3% NGLs, all of which were classified as proved developed. Including adjustments from an effective date of July 1, 2012, the adjusted purchase price was $205.6 million and we assumed the ARO associated with the Newfield Properties, which we have estimated to be $31.7 million. The acquisition was initially funded from borrowings under our revolving bank credit facility and cash on hand. Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of an additional $300.0 million of 8.50% Senior Notes.

During 2011, we closed two acquisition transactions. In May 2011, we acquired from Opal approximately 24,500 gross acres (21,900 net acres) of certain oil and gas leasehold interests in the Permian Basin of West Texas, which we refer to as our Yellow Rose Properties. Internal estimates of proved reserves associated with the Yellow Rose Properties as of the acquisition date were approximately 30.1 MMBoe (180.4 Bcfe), comprised of approximately 69% oil, 22% NGLs and 9% natural gas, and approximately 70% of which were classified as proved undeveloped. Including adjustments from an effective date of January 1, 2011, the adjusted purchase price was $394.4 million, and we assumed the ARO associated with the Yellow Rose Properties, which we have estimated to be $0.4 million, and recorded a long-term liability of $2.1 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

In August 2011, we acquired from Shell its 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas treatment plant. Internal estimates of proved reserves associated with the Fairway Properties as of the acquisition date were 8.9 MMBoe (53.5 Bcfe), comprised of approximately 72% natural gas, 27% NGLs and less than 1% oil, all of which are proved developed producing. Including adjustments

from an effective date of September 1, 2010, the adjusted purchase price was $42.9 million and we assumed the ARO associated with the Fairway Properties, which we have estimated to be $7.8 million. The acquisition was funded from borrowings under our revolving bank credit facility.

See Financial Statements – Note 2 – Acquisitions and Divestitures under Part II, Item 8 of this Form 10-K for additional information on acquisitions.

From time to time, as part of our business strategy, we sell various properties that we consider non-core assets. In 2012, we sold our 40%, non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico for $30.5 million. In connection with this sale, we reversed $4.0 million of ARO. In 2011 and 2010, there were no property sales of significance.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for 2012 were comprised of approximately 35% oil and condensate, 12% NGLs and 52% natural gas, determined using the energy-equivalent ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs. The energy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices per Mcfe for oil, NGLs and natural gas may differ significantly. For 2012, our combined total production of oil, NGLs and natural gas was approximately 1.3% higher on a Mcfe basis than during the same period in 2011.

During 2012, sales volumes were negatively impacted by Hurricane Isaac, Tropical Storm Debbie and various pipeline outages. Our estimate of the impact of these items on 2012 volumes was approximately 0.8 MMBoe (4.8 Bcfe).

During 2012, our average realized oil sales price (unhedged) decreased to $104.35 per barrel compared to $105.92 per barrel in 2011. Two comparable benchmarks are the unweighted average daily posted spot price of West Texas Intermediate (“WTI”) crude oil and the unweighted average daily posted spot price of Brent crude oil, which decreased 0.9% and increased 0.3%, respectively, from 2011. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price plus a premium depending on the type of crude oil. Most of our oil production is from our offshore operations and is comprised of various crudes including Heavy Louisiana Sweet, Light Louisiana Sweet, Poseidon and others. Starting in the first quarter of 2011 and continuing through the fourth quarter of 2012, these various crudes sold at a significant premium relative to WTI. During 2012, premiums for Heavy Louisiana Sweet crude and Light Louisiana Sweet crude ranged between $10.00 and $22.00 per barrel. For the month of December 2012, the average premium for these crudes was between $21.00 and $22.00 per barrel. In comparison, the premium for these crudes was between $4.00 and $30.00 per barrel for 2011. In 2010, the premium was approximately $2.00 to $3.00 per barrel, which is representative of the historical norm. We may continue to experience higher premiums to WTI crude in our future sales of crude oil until such time as the causative factors, described below, are resolved. We cannot predict with any certainty how long such pricing conditions will last.

A possible cause cited by industry publications for the premiums afforded our offshore crudes is an oversupply situation at Cushing, Oklahoma, a primary domestic hub for crude oil priced using the WTI benchmark. Citing the Cushing crude over supply situation, the owners of the Seaway pipeline reversed the flow of crude oil in June 2012 to flow crude from Cushing to Freeport, Texas. Although this change increased the amount of crude oil available to Gulf Coast refineries, we did not experience a decline in premiums in the second half of 2012. In January 2013, the Seaway pipeline capacity was increased from 150,000 barrels per day to 400,000 barrels per day. The owners have announced plans to construct a parallel pipeline to be completed in the first quarter of 2014, which is expected to increase the capacity to 850,000 barrels per day. Other pipeline projects are underway as well that, when added to the Seaway pipeline capacity, could bring 1.9 million barrels per day of mid-continent crude oil to the Gulf Coast. That capacity is expected to grow to 2.4 million barrels per day by the end of 2014. We believe these actions may substantially reduce the oversupply situation at Cushing,

which may affect the premiums we receive on our offshore oil production. An additional factor that has appeared to affect the premiums for Heavy Louisiana Sweet and Light Louisiana Sweet is the difference between the Brent and WTI crude oil prices, which continue to have a higher spread than historical norms. When the price of Brent crude increases relative to WTI, the value of low-sulfur U.S. crude grades that compete with West African crude increases. This trend of higher Brent spreads began in the first quarter of 2011 and continued through December 2012.

Oil prices are affected by world events, such as political unrest in the Middle East, the threat of hostilities, demand changes in various countries and world economic growth. Some commentators believe world economic growth, which is currently being affected by the economies of China, Brazil, India and Russia, may support strong crude oil prices in the long term.

Not-withstanding this long-term view, crude oil prices will likely continue to be volatile. For 2012, WTI crude oil prices ranged from a high of approximately $109.00 per barrel to a low of $78.00 per barrel. The volatility in price was attributed by some commentators to be due in part to the debt crisis in Europe and the belief that economic growth in certain world markets was weakening. The U.S. Energy Information Administration (“EIA”) expects the oil market to loosen in the near term as supply increases are expected to be higher than consumption increases. EIA expects inventories to build in the first half of 2013. Supply increases are expected from the United States and other Non-OPEC countries. Consumption increases are expected in China and other countries outside of the Organization for Economic Cooperation and Development. EIA projections do not assume any significant deterioration of the economies of the United States and European Union. EIA projects crude prices for Brent and WTI will be lower in 2013 compared to 2012. Estimates of global oil demand by EIA for 2012 and 2013 were 89.0 and 90.0 million barrels per day, respectively, which would be approximately 1% growth year over year.

Our average realized NGLs sales prices (unhedged) decreased 28.8% during 2012 compared to 2011. According to industry sources, domestic NGLs production significantly increased over 2011 levels which affected price realizations. During 2012, prices for domestic ethane and propane, two common NGL components, decreased 52% and 31%, respectively, from 2011 and other domestic NGLs prices decreased 8% to 12%. As long as ethane and propane inventories continue to be high and NGLs production continues to increase, we could expect prices for these two commodities to be weak. In addition, as long as the crude to natural gas price ratio remains wide, NGLs production may continue to be high, which may put downward pressure on the entire NGLs stream. In addition, many natural gas processing facilities are re-injecting ethane back into the natural gas stream after processing due to increasing ethane supplies. This in turn increases natural gas supplies and has helped to lead to lower natural gas pricing.

Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues and domestic economic conditions, and they have historically been subject to substantial fluctuation. During 2012, the average realized sales price for our natural gas production decreased 28.6% from 2011 to $2.94 per Mcf. A comparable bench mark is the Henry Hub unweighted average daily posted spot price, which decreased 31.3% from the comparable period. We expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas storage levels building to high levels throughout the injection season, (iii) natural gas continuing to be produced as a by-product in conjunction with the substantial ramp up of oil drilling, (iv) increasing availability of liquefied natural gas, (v) production efficiency gains are achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling and production techniques and (vi) re-injecting ethane into the natural gas stream as indicated above which increases the natural gas supply. EIA estimates that natural gas consumption in 2012 increased 4.8% from 2011 to 69.7 billion cubic feet per day due to gains in electrical power use offsetting declines in residential and commercial consumption and expects 2013 consumption to decline slightly from 2012 levels. The EIA expects production growth to increase slightly in 2013 as the associated gas with crude oil drilling will offset the declines in natural gas drilling. According to

Baker Hughes, the natural gas rig count at the end of 2012 is down approximately 50% compared with the start of 2012. EIA expects the Henry Hub natural gas price will average $3.79 per Mcf in 2013 compared to an estimated $2.86 per Mcf in 2012. Due to the high production and historically high inventory levels, we believe natural gas prices may continue to be weak until such time as crude prices weaken (which will in turn decrease oil drilling activity and decrease the likelihood of producing natural gas as a byproduct), economic activity increases dramatically or fuel switching increases. During 2012, U.S. energy producers switched from coal-powered energy to natural gas, estimated by the EIA at approximated 4 Bcfe per day, particularly during the summer cooling season. Industry sources have indicated that a price above $3.50 per Mcf will probably cause power producers to switch back to coal from natural gas, which in effect creates limits to how far natural gas prices can rise until such time as demand for natural gas increases from other sources.

In 2012, 2011 and 2010, we did not incur an impairment write-down. Should prices decline for oil, NGLs and natural gas in the future, our future oil, NGL and natural gas revenues, earnings and liquidity would be negatively impacted, and could result in impairment write-downs of the carrying value of our oil and natural gas properties. This decline could create issues with financial ratio compliance, and could result in a reduction of the borrowing base associated with our credit agreement, depending on the severity of such declines. If those factors were to occur and were significant, the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry in the future could be impacted.

Our operating costs include the expense of operating our wells, platforms and other infrastructure primarily in the Gulf of Mexico and Texas and transporting our production to the point of sale. Our operating costs are generally comprised of several components, including direct operating costs, repairs and maintenance, gathering and transportation costs, production taxes, workover costs and ad valorem taxes. Our operating costs depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties.

Revenue from our production is highly dependent on pipelines owned by others to access markets for our products. To the extent that the transportation rate such pipelines charge increases, our revenues from the sales of our products would go down or transportation costs would increase, the result of either would be a reduction in operating income. We have reached agreements with certain gas pipelines that significantly reduce the rates we are charged relative to their most recent filed tariff rates, but still represent an increase from prior rates that will negatively impact our operating income. For other third-party pipelines that handle our product, the potential transportation rate changes and timing are not known at this time. The approval process typically results in approval of fees less than those contained in the filing requests. The combined impact cannot be specifically determined, as the impact is dependent on volumes, the amount of transportation rate change for certain pipeline operators and the timing of such changes. However, we estimate that the combined detrimental impact to operating income in excess of the impact experienced in 2012 for these pipelines’ price changes may be up as much as $10.0 million for 2013.

In recent years, we acquired and built platforms near the outer edge of the continental shelf and operated wells in the deepwater of the Gulf of Mexico. To the extent we continue our deepwater operations, our operating costs will likely increase. While each field can present operating problems that can add to the costs of operating a field, the production costs of a field are generally directly proportional to the number of production platforms built in the field. As technologies have improved, oil and natural gas can be produced from larger acreage areas using a single platform, which may reduce the operating costs associated with future development projects.

Our operations are exposed to potential damage from hurricanes and we obtain insurance to reduce our financial exposure risk. We incurred substantial costs from 2008 through 2012 for hurricane related damage occurring in 2008 and expect to incur costs through 2013 to complete plugging and abandonment work primarily related to three toppled platforms. We received reimbursements from our insurance carrier in each of the last four years and expect to receive additional reimbursements for covered costs incurred in future periods as covered

costs incurred to date have not exceeded policy limits. See Liquidity and Capital Resources below and Financial Statements – Note 3 – Hurricane Remediation and Insurance Claims under Part II, Item 8 in this Form 10-K for additional information.

Applicable environmental regulations require us to remove our platforms after production has ceased, to plug and abandon all wells and to remediate any environmental damage our operations may have caused. The costs associated with our ARO generally increase as we drill wells in deeper parts of the continental shelf and in the deepwater. We generally do not pre-fund our ARO. We estimated the present value of our liability related to our ARO at $384.1 million as of December 31, 2012. Inherent in the present value calculation of our liability are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and expenditure, and changes in the legal, regulatory, environmental and political environments. Actual expenditures for ARO could vary significantly from these estimates.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico which caused loss of life, caused the rig to sink and created a major oil spill that produced economic, environmental and natural resource damage. Subsequently, the BOEM issued a series of NTLs and other significant changes in regulations and implemented a six-month moratorium on drilling activities which began in May 2010. After the drilling moratorium ended in November 2010, it was not until March 2011 that deep water drilling permits began to be issued, and even then only sporadically, to continue drilling activities that had commenced prior to the Deepwater Horizon incident. Since March 2011, deepwater drilling permits have been issued, albeit at a slower and much more measured pace than before the Deepwater Horizon event. The most significant regulatory changes since the Deepwater Horizon event are regulations related to assessing the potential environmental impact of future spills using worse case discharge scenarios on a well-by-well basis, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time it takes to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time. The permitting process is also slow and inconsistent for shallow water work and even for plug and abandonment activities. This could lead to increased costs and performing work at less than optimal effectiveness or even at less than desirable times due to weather. We have not experienced delays in obtaining permits related to our onshore operations.

Results of Operations

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Revenues. Total revenues decreased $96.6 million, or 9.9%, to $874.5 million in 2012 compared to 2011. Oil revenues decreased $13.7 million, NGLs revenues decreased $20.9 million, natural gas revenues decreased $62.8 million and other revenues increased $0.9 million. The oil revenue decrease was attributable to a 1.5% decrease in the average realized sales price (unhedged) to $104.35 per Bbl in 2012 from $105.92 per Bbl in 2011, with sales volumes decreasing slightly. The NGLs revenue decrease was attributable to a 28.8% decrease in the average realized sales price (unhedged) to $39.75 per Bbl in 2012 from $55.81 per Bbl in 2011, partially offset by an increase of 12.5% in sales volumes. The natural gas revenue decrease was attributable to a 28.6% decrease in the average realized natural gas sales price (unhedged) to $2.94 per Mcf from $4.12 per Mcf for 2011, with sales volumes increasing slightly. The sales volumes for all commodities were negatively impacted by Hurricane Isaac, Tropical Storm Debbie, various pipeline outages, and natural production declines, and were positively impacted by acquisitions and successful exploration and development efforts.

basis, base lease operating expenses, workover costs, insurance premiums and hurricane remediation costs net of insurance claims increased $7.4 million, $6.8 million, $2.9 million and $0.9 million, respectively. As a partial offset, facility expenses decreased $4.9 million. The increase in base lease operating expenses is primarily attributable to acquisitions in 2012 and 2011. Workover cost increases were primarily attributable to increases for our onshore operations, which had approximately four months of expenses in 2011. The increase in insurance premiums is attributable to increases effective with the June 1, 2011 renewal, which included an expansion in coverage and led to higher expenses in the first half of 2012. The decrease in facilities expense is primarily attributable to work performed in 2011 on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform, the pipeline repairs at our Ship Shoal 300 field to remove paraffin and inspection fees at our Main Pass 252 platforms. These projects were only partially offset by other projects in 2012.

Production taxes. Production taxes increased to $5.8 million during 2012 compared to $4.3 million in 2011 primarily due to the Yellow Rose Properties and the Fairway Properties’ operations and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs decreased to $14.9 million in 2012 from $16.9 million in 2011 due to a higher percentage of onshore volumes, where transportation fees are lower.

Depreciation, depletion, amortization and accretion (“DD&A”). DD&A, including accretion for ARO, increased to $3.47 per Mcfe for 2012 from $3.24 per Mcfe for 2011. On a nominal basis, DD&A increased to $356.2 million for 2012 from $328.8 million in 2011. The increase in DD&A on a per Mcfe and nominal basis was due in part to costs capitalized to the full cost pool from both the unevaluated pool and from increases in our ARO estimates without a corresponding increase in proved reserves. In addition, we incurred significant development capital throughout the year that did not lead to an increase in proved reserves. Finally, most of our reserve additions for 2012 occurred late in the year.

General and administrative expenses (“G&A”). G&A increased to $82.0 million for 2012 from $74.3 million for 2011. Included in 2012 is $13.9 million that relates to the settlement of environmental claims made by certain landowners in Cameron Parish, Louisiana, the settlement with the Department of Justice of an environmental enforcement claim and associated legal costs. These costs exceeded similar amounts incurred in 2011 by $9.5 million. In addition, the overhead that we bill out to our joint interest parties was higher in the 2012 period by $1.9 million primarily due to a full year of operations at our Fairway Properties and increased drilling activities. The 2011 period included higher payments for transition services associated with the acquisitions completed in that year. On a per Mcfe basis, G&A was $0.80 per Mcfe for 2012, compared to $0.73 per Mcfe for 2011. See Financial Statements – Note 11 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 of this Form 10-K for additional information.

Derivative (gain) loss. For 2012 and 2011, we recognized a loss of $14.0 million and a gain of $1.9 million, respectively, related to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices relative to the prices at the beginning of the period. Although the contracts relate to production for both the current and future years, changes in the fair value for all open contracts are recorded currently. For 2012, the loss was comprised of a $7.7 million realized loss and a $6.3 million unrealized loss. For 2011, the gain was comprised of a $9.9 million realized loss and an $11.8 million unrealized gain. See Financial Statements – Note 6 – Derivative Financial Instruments under Part II, Item 8 of this Form 10-K for additional information.

Interest expense. Interest expense incurred increased to $63.3 million for 2012 from $52.4 million for 2011 with the increase primarily attributable to the issuance of Senior Notes. The average amount of our Senior Notes outstanding increased due to our June 2011 issuance of $600.0 million of our 8.50% Senior Notes and repurchase of $450.0 million of our 8.25% Senior Notes. In addition, we issued an additional $300.0 million of 8.50% Senior Notes in October 2012. During 2012 and 2011, interest of $13.3 million and $9.9 million, respectively,

were capitalized to unevaluated oil and natural gas properties. The increase is primarily attributable to the acquisition of the Yellow Rose Properties in 2011. See Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information.

Loss on extinguishment of debt. In 2012, no loss on extinguishment of debt was incurred. For 2011, loss on extinguishment of debt was $22.7 million. In 2011, we expensed repurchase premiums, deferred financing costs and other costs totaling $22.0 million related to the repurchase of $450.0 million in aggregate principal amount of our 8.25% Senior Notes due 2014 and expensed $0.7 million of deferred financing costs related to replacement of our revolving bank credit facility. See Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information.

Income tax expense. Income tax expense decreased to $47.5 million for 2012 compared to $91.5 million for 2011. Our effective tax rate for 2012 was 39.8% and differed from the federal statutory rate of 35% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the Internal Revenue Code (“IRC”) as a function of loss carrybacks to prior years and the impact of state income taxes. Our effective tax rate for 2011 was 34.6% and differed from the federal statutory rate of 35% primarily as a result of the deduction for qualified domestic production activities under Section 199 of the IRC.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Revenues. Total revenues increased $265.3 million, or 37.6%, to $971.0 million in 2011 compared to 2010. Oil revenues increased $189.8 million, NGLs revenues increased $53.6 million, natural gas revenues increased $17.7 million and other revenues increased $4.2 million. The oil revenue increase was attributable to a 37.0% increase in the average realized sales price (unhedged) to $105.92 per Bbl in 2011 from $77.33 per Bbl in 2010, combined with an increase of 3.4% in sales volumes. The NGLs revenue increase was attributable to a 27.9% increase in the average realized sales price (unhedged) to $55.81 per Bbl in 2011 from $43.65 per Bbl in 2010, combined with an increase of 58.3% in sales volumes. The sales volume increase for oil and NGLs is primarily attributable to increases associated with properties acquired in 2011 and 2010. The natural gas revenue increase resulted from a 20.1% increase in sales volumes, partially offset by a 9.5% decrease in the average realized natural gas sales price (unhedged) to $4.12 per Mcf compared to $4.55 per Mcf for 2010. The sales volume increase for natural gas is primarily attributable to increases associated with our acquisition activities, the Main Pass 108 fields resuming production and successful exploration efforts. Other revenue changed primarily due to a disallowance of $4.7 million by the ONRR in 2010 of royalty relief for transportation of deepwater production through our subsea pipeline system. We are contesting this ONRR adjustment. For additional information, see Financial Statements – Note 19 – Contingencies under Part II, Item 8 of this Form 10-K.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $49.5 million to $219.2 million in 2011 compared to 2010. On a per Mcfe basis, lease operating expenses increased to $2.16 per Mcfe during 2011 compared to $1.95 per Mcfe during 2010. On a component basis, base lease operating expenses, facility expenses, hurricane remediation costs net of insurance claims, and workover costs increased $20.7 million, $14.1 million, $11.7 million and $3.6 million, respectively. As a partial offset, insurance premiums decreased $0.6 million. The increase in base lease operating expenses is primarily attributable to expenses associated with the properties acquired in 2011 and 2010, higher costs at our various non-operated properties and increased processing fees associated with our Daniel Boone field production. The increase in facility expenses is primarily attributable to work performed on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform, the pipeline repairs at our Ship Shoal 300 field to remove paraffin and inspection fees at our Main Pass 252 platforms. Hurricane remediation costs net of insurance claims increased primarily due to higher reimbursements received in 2010. Workover costs increased due to work performed at our Yellow Rose Properties and expenses at the Main Pass 108 field, partially offset by projects in 2010 that did not occur in 2011. The decrease in insurance premiums resulted primarily from lower premiums on our insurance policies covering well control and hurricane damage that cover the policy period June 1, 2010 to

June 1, 2011. Our premiums increased effective with the June 1, 2011 renewal attributable to a substantial improvement in coverage. For additional information, see Liquidity and Capital Resources – Hurricane Remediation and Insurance Claims.

Production taxes. Production taxes increased to $4.3 million during 2011 compared to $1.2 million in 2010 primarily due to the Yellow Rose Properties and the Fairway Properties’ operations and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs were basically flat for 2011 compared to the prior year.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $3.24 per Mcfe for 2011 from $3.38 per Mcfe for 2010. On a nominal basis, DD&A increased to $328.8 million for 2011 from $294.1 million in 2010. The decrease in DD&A on a per Mcfe basis was primarily due to increases in proved reserves while DD&A on a nominal basis increased due to higher production volumes.

General and administrative expenses. G&A increased to $74.3 million for 2011 from $53.3 million for 2010 due to a number of factors including higher incentive compensation as a result of improved financial and operational performance, costs related to expanded onshore and offshore activities, acquisitions, surety premiums, transition services fees paid to the sellers of the acquired properties, and litigation related costs. Also, we earned administration fees in 2010 related to an asset disposition, and no such fees were earned in 2011. On a per Mcfe basis, G&A was $0.73 per Mcfe for 2011, compared to $0.61 per Mcfe for 2010. See Financial Statements – Note 11 – Share-Based and Cash-Based Incentive Compensation under Part II, Item 8 of this Form 10-K for additional information.

Derivative (gain) loss. For 2011 and 2010, we recognized a gain of $1.9 million and a loss of $4.3 million, respectively, related primarily to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices relative to the prices at the beginning of the period. Although the contracts relate to production for both the current and future years, changes in the fair value for all open contracts are recorded currently. For 2011, the gain was comprised of a $9.9 million realized loss and an $11.8 million unrealized gain. For 2010, the loss was comprised of a $0.8 million realized gain and a $5.1 million unrealized gain. Included in 2010 was a derivative loss of $0.3 million related to our interest rate swap. See Financial Statements – Note 6 – Derivative Financial Instruments under Part II, Item 8 of this Form 10-K for additional information.

Interest expense. Interest expense incurred increased to $52.4 million for 2011 from $43.1 million for 2010, with the increase primarily attributable to our Senior Notes. The average amount of our Senior Notes outstanding increased due to our June 2011 issuance of $600.0 million of our 8.50% Senior Notes and repurchase of $450.0 million of our 8.25% Senior Notes. During 2011 and 2010, $9.9 million and $5.4 million, respectively, of interest were capitalized to unevaluated oil and natural gas properties which increased due to the Yellow Rose Properties acquisition. See Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information.

Loss on extinguishment of debt. For 2011, loss on extinguishment of debt was $22.7 million. In 2011, we expensed repurchase premiums, deferred financing costs and other costs totaling $22.0 million related to the repurchase of $450.0 million in aggregate principal amount of our 8.25% Senior Notes due 2014 and expensed $0.7 million of deferred financing costs related to replacement of our revolving bank credit facility. In 2010, no loss on extinguishment of debt was incurred. See Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information.

Income tax expense. Income tax expense increased to $91.5 million for 2011 compared to $11.9 million for 2010. Our effective tax rate for 2011 was 34.6% and differed from the federal statutory rate of 35% primarily as a result of the deduction for qualified domestic production activities under Section 199 of the IRC. Our effective

tax rate for 2010 was 9.2% and primarily reflects a reduction in our valuation allowance against our deferred tax assets and the utilization of the deduction attributable to qualified domestic production activities under Section 199 of the IRC. Taxable income in 2010 allowed us to reverse all of our previously recorded valuation allowance.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to grow our oil and natural gas reserves, repay outstanding borrowings and make related interest payments and pay dividends. We have funded such activities with cash on hand, cash provided by operating activities, securities offerings and bank borrowings. These sources of liquidity have historically been sufficient to fund our ongoing cash requirements.

Cash flow and working capital. Net cash provided by operating activities for 2012 was $385.1 million, compared to $521.5 million for 2011. The decrease is primarily attributable to lower realized prices for natural gas and NGLs, higher payments related to ARO and increases in joint interest receivables. Partially offsetting the decrease were lower payments related to income taxes of $16.1 million in 2012 compared to $35.7 million in 2011, and higher production volumes. Our combined average realized sales price per Mcfe (hedged) during 2012 was 11.1% lower than the comparable 2011 period, while our combined production of oil, NGLs and natural gas on a natural gas equivalent basis during 2012 was 1.3% higher than 2011.

Net cash used in investing activities during 2012 and 2011 was $657.4 million and $722.7 million, respectively, which primarily represents our investments in oil and natural gas properties. Cash used in investing activities for 2012 includes the acquisition of the Newfield Properties for $205.6 million. Cash used in investing activities for 2011 includes the acquisitions of the Yellow Rose Properties for $394.4 million and the Fairway Properties for $42.9 million. In addition, investments in other oil and natural gas properties and equipment were $479.3 million in 2012 compared to $281.8 million in 2011, with the increase primarily related to drilling activities onshore and in deepwater offshore areas.

Net cash provided by financing activities was $280.0 million during 2012. Funds were provided through the issuance of an additional $300.0 million of 8.50% Senior Notes at a premium of 106% to par, which after netting debt issuance costs, provided $312.0 million. In addition, $53.0 million was provided through net borrowings on our revolving bank credit facility. Funds used were primarily attributable to the payment of dividends of $82.8 million, which includes two special dividends totaling $59.0 million. Net cash provided by financing activities was $177.1 million during 2011. Funds were provided through net borrowings on the revolving bank credit facility of $117.0 million and issuance of $600.0 million of 8.50% Senior Notes and partially offset by the repurchase of $450.0 million of the 8.25% Senior Notes and repurchase premium and debt issuance costs of $32.3 million. In addition, dividend payments were $58.8 million in 2011, which included a special dividend of $46.9 million. See Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information on the Senior Note transactions.

At December 31, 2012, we had a cash balance of $12.2 million and $554.4 million of undrawn capacity available under the revolving bank credit facility, which had a borrowing base of $725.0 million as of December 31, 2012.

Credit agreement and long-term debt. At December 31, 2012, $170.0 million was outstanding under our revolving bank credit facility compared to $117.0 million at December 31, 2011. At December 31, 2012 and 2011, $900.0 million and $600.0 million principal amount, respectively, of our 8.50% Senior Notes were outstanding. We believe that cash provided by operations, borrowings available under our revolving bank credit facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements.

On May 7, 2012, we executed the First Amendment to the Fourth Amended and Restated Credit Agreement (the “First Amendment”), which, among other things, increased the number of participating lenders and added a

provision permitting the Company to maintain security interest in favor of any derivative counterparties that cease to be lenders under the Company’s revolving bank credit facility. On October 12, 2012, we executed the Second Amendment to the Fourth Amended and Restated Credit Agreement (the “Second Amendment”), which, among other things, allowed for the issuance of additional senior unsecured indebtedness with an automatically and simultaneously reduction in the borrowing base by $0.25 for every $1.00 of unsecured indebtedness incurred above $600.0 million aggregate principal amount of our existing notes until such time as the borrowing base has been determined or otherwise adjusted. All other terms of the Credit Agreement remain substantially the same prior to the First and Second Amendment including the termination date of May 5, 2015, interest rate spreads and covenants. Fees related to the First and Second Amendments were approximately $2.5 million, which are being amortized over the remaining term of the Credit Agreement.

Effective on November 7, 2012, our borrowing base was increased to $725.0 million and the number of lenders increased. We currently have 20 lenders within the revolving bank credit facility, with commitments ranging from $20.0 million to $56.0 million for the current borrowing base. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively impact our liquidity position.

Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the size of our revolving bank credit facility. Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate or LIBOR, plus applicable margins ranging from 2.00% to 2.75%, or an alternate base rate equal to the greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, and (c) LIBOR plus 1%, plus applicable margins ranging from 1.00% to 1.75%. The unused portion of the borrowing base is subject to a commitment fee of 0.50%.

The Credit Agreement contains covenants that limit, among other things, the payment of cash dividends in excess of $60.0 million per year, common stock repurchases and Senior Note repurchases in excess of $100.0 million in the aggregate, borrowings other than from the revolving bank credit facility, sales of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders. In December 2012, we were granted a one-time waiver which allowed for cash dividends of up to $85.0 million during 2012. The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of December 31, 2012.

During 2012, the outstanding borrowings on the revolving bank credit facility reached a high of $330.0 million primarily to fund the acquisition of the Newfield Properties. These borrowings were reduced to $170.0 million as of December 31, 2012. Letters of credit outstanding as of December 31, 2012 were $0.6 million.

On October 24, 2012, we issued an additional $300.0 million of 8.50% Senior Notes at a premium of 106% par value with an interest rate of 8.50% and maturity date of June 15, 2019, which have identical terms to the Senior Notes issued in June 2011. The proceeds were used to pay down amounts outstanding on the revolving bank credit facility. The 8.50% Senior Notes mature on June 15, 2019 and interest is payable semi-annually in arrears on June 15 and December 15 of each year. See Financial Statements – Note 7 – Long-Term Debt under Part II, Item 8 of this Form 10-K for additional information about our Credit Agreement and long-term debt. We were in compliance with all applicable covenants related to the 8.50% Senior Notes as of December 31, 2012.

In January 2012, holders of the $600.0 million 8.50% Senior Notes issued in June 2011 exchanged their Senior Notes for registered notes with the same terms. In February 2013, holders of the $300.0 million 8.50% Senior Notes issued in October 2012 exchanged their Senior Notes for registered notes with the same terms.

From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. As of December 31, 2012, our outstanding derivative instruments consisted of commodity swap oil contracts relating to approximately 1.3 MMBbls and 0.7 MMBbls of our anticipated oil production for 2013 and 2104, respectively. During January and February of 2013, we have entered into additional derivative contracts for oil related to our anticipated 2013 and 2014 production. See Financial Statements – Note 6 – Derivative Financial Instruments under Part II, Item 8 of this Form 10-K for additional information about our derivatives.

Hurricane Remediation and Insurance Claims. During the third quarter of 2008, Hurricane Ike caused substantial property damage and we continue to incur costs and submit claims to our insurance underwriters related to repairing such damage. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

Through December 31, 2012, we have received cash from our insurance carrier related to Hurricane Ike claims totaling $142.2 million and have no insurance receivables recorded as of December 31, 2012 for claims that have been submitted and approved for payment. As of December 31, 2012, we have recorded in ARO an estimate of $6.6 million for additional costs to be incurred related to Hurricane Ike and we have estimated that this work will be completed by the end of 2013. We expect to receive reimbursement for a portion of these costs once costs are incurred and claims submitted. In addition, we have incurred removal of wreck costs related to Hurricane Ike, but some of our insurance carriers are disputing whether such costs are covered costs; therefore, we cannot estimate the amount of reimbursement to be received at this time. Should necessary expenditures exceed our insurance coverage for damages incurred as a result of Hurricane Ike, or claims are denied or there are significant delays in recovering further claims for other reasons, we expect that our available cash on hand, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet these future cash needs.

During the fourth quarter of 2012, underwriters of W&T’s excess liability policies (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company; XL Specialty Insurance Company and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that such policies do not cover removal of wreck and debris claims arising from Hurricane Ike that occurred in 2008. The court consolidated the various suits filed by underwriters. W&T has not yet filed any claim under such excess policies, but W&T anticipates that such claims may reach $50.0 million in aggregate. In January 2013, the Company filed a motion for summary judgment seeking the court’s determination that such excess policies do in fact provide coverage for such removal of wreck and debris claims. The motion for summary judgment is pending. If successful, we expect to receive reimbursement for these costs once costs have been incurred and claims submitted. We have incurred $45.6 million to date and expect to incur an additional $5.0 million in costs related to removal of wreck associated with platforms damaged by Hurricane Ike. Removal-of-wreck costs are recorded in Oil and natural gas properties and equipment on the Consolidated Balance Sheet. Any recoveries from claims made on these policies related to this issue will be recorded as reductions in this line item, which will reduce our DD&A rate and replenish our cash expenditures.

For a discussion of our hurricane remediation costs related to lease operating expenses incurred during 2012, 2011 and 2010, refer to Financial Statements – Note 3 – Hurricane Remediation and Insurance Claims under Part II, Item 8 of this Form 10-K. We expect that the majority of insurance reimbursements subsequent to December 31, 2012 will be attributable to plugging and abandonment activities. Insurance reimbursements related to plugging and abandonment activities are recorded as reductions to Oil and natural gas properties on the Consolidated Balance Sheet, which would affect future DD&A expense.

We currently carry three layers of insurance coverage for our operating activities in the Gulf of Mexico. The current policy limits for well control and hurricane damage (defined as named windstorm in our policies) are up to $100.0 million and $140.0 million, respectively, and the policies are effective until June 1, 2013. We carry an additional $100.0 million of well control coverage effective until June 1, 2013 on certain wells at our Mahogany, Matterhorn, Virgo, Main Pass 107/108, Tahoe and SE Tahoe fields. A retention amount of $5.0 million for well control events and $40.5 million per hurricane occurrence must be satisfied by us before we are indemnified for losses. Pollution causing a negative environmental impact is characterized as a covered component of each of the well control and hurricane sections of the policy.

We estimate that as of December 31, 2012, approximately 91% of the estimated future net revenues discounted at 10% (PV-10) attributable to our Gulf of Mexico properties are on platforms that are covered under our current insurance policies for named windstorm damage. The percentage of our PV-10 value fields that are covered are less than last year due to the acquisition of the Newfield Properties. Since we closed on the Newfield Properties near the end of named windstorm season and much of the property value is in subsea wells, we elected not to purchase named windstorm insurance on the assets. There are certain other properties we have deemed as non-core and do not cover for named windstorm damage.

Our general and excess liability policy is effective until May 1, 2013 and provides for $250.0 million of liability coverage for bodily injury and property damage, including liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility requirement under the Ocean Pollution Act, we are required to evidence $150.0 million of financial responsibility to the BSEE. We qualify to self-insure for $35.0 million of this amount and the remaining $115.0 million is covered by insurance.

The premiums for the above policies were $30.6 million for the May/June 2012 policy renewals compared to $32.3 million for the expiring policies. The decrease in our premiums effective with the June 1, 2012 renewal was primarily attributable to an improved insurance market, likely due to less windstorm activity. We do not carry business interruption insurance.

Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil and natural gas, acquisition opportunities, and the results of our exploration and development activities. The following table presents our capital expenditures for acquisitions, exploration, development and other leasehold costs:


	Year Ended December 31,
	2012		2011			2010
	(in thousands)
Acquisition of Newfield Properties	$	205,550	$	—		$	—
Acquisition of Yellow Rose Properties		—		394,377			—
Acquisition of Fairway Properties		—		42,870			—
Acquisition of (adjustments to) Tahoe Properties		—		(5,700	)		121,933
Acquisition of properties from Total E&P		—		—			115,012
Exploration (1)		137,055		77,606			60,164
Development (1)		310,205		179,705			77,230
Seismic, capitalized interest, other leasehold costs		32,053		30,168			41,314

Acquisitions and investments in oil and gas property/equipment	$	684,863	$	719,026		$	415,653

(1)	Reported geographically in the subsequent table.

The following table presents our exploration and development capital expenditures geographically:


	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Conventional shelf	$	104,401	$	132,680	$	115,503
Deepwater		65,856		4,826		9,358
Deep shelf		11,961		5,833		3,382
Onshore		265,042		113,972		9,151

Exploration and development capital expenditures	$	447,260	$	257,311	$	137,394

The following table sets forth our drilling activity on a gross basis.


	Completed						Non-commercial
	2012		2011		2010		2012		2011		2010
Offshore – gross wells drilled:
Conventional shelf		3		7		6		1		—		1
Deep shelf		1		1		—		—		—		—

Wells operated by W&T		3		7		3		n/a		n/a		n/a

Onshore:
Gross wells drilled		77		39		—		—		1		2

Wells operated by W&T		73		33		—		n/a		n/a		n/a

As of December 31, 2012, we were in the process of drilling and/or completing nine onshore development wells in Texas, six onshore exploration wells in Texas, two offshore exploration wells and one offshore development well.

See Properties – Drilling Activity under Part I, Item 2 of this Form 10-K for a breakdown of exploration and development wells and additional drilling activity information.

See Properties – Development of Proved Undeveloped Reserves under Part I, Item 2 of this Form 10-K for a discussion on activity related to proved undeveloped reserves.

In 2012, we acquired 11 leases from the BOEM for $2.5 million. In 2011, we did not participate in bidding for any Gulf of Mexico leases on the OCS. Due to the government mandated moratorium that began in April 2010, Gulf of Mexico lease sales conducted by the U.S. government through the BOEM were suspended until December 2011. Leases acquired from the BOEM in the March 2010 lease sale totaled five leases for $8.7 million.

From time to time, we sell various oil and gas properties for a variety of reasons including, change of focus, perception of value and to reduce debt, among other reasons. In 2012, we sold our 40% non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico for $30.5 million and reduced ARO by $4.0 million. In 2011 and 2010, there were no property sales of significance.

Our total capital expenditure budget for 2013 currently is $450.0 million, not including any potential acquisitions. The budget includes 63% for exploration and 37% for development and these percentages include amounts for facilities capital, recompletions, seismic and leasehold items. Geographically, the budget includes 63% for offshore (11 wells) and 37% for onshore. The budget for offshore includes two deepwater wells and a joint interest arrangement in another deepwater well, of which we are not the operator. The budget for onshore includes 27 wells in the Yellow Rose Properties and amounts currently designated for our Terry County and East Texas prospects for completion work and additional wells, which require further evaluation. Our 2013 capital budget is subject to change as conditions warrant and we strive to be as flexible as possible.

We intend to continue to pursue acquisitions and joint venture opportunities during 2013 should we identify attractive opportunities. We are actively evaluating opportunities and expect to complement our drilling and development projects with acquisitions providing acceptable rates of return. We anticipate funding our 2013 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving loan facility, and accessing the capital markets to the extent necessary.

Dividends. In 2012, we paid $82.8 million in dividends, which included two special dividends totaling $59.0 million and regular dividends of $23.8 million. In 2011, we paid $58.8 million in dividends, which included a special dividend of $46.9 million and regular dividends of $11.9 million. In 2010, we paid $59.6 million in dividends, which included a special dividend of $49.2 million and regular dividends of $10.4 million. Future special dividends cannot be predicted and are subject to approval of the board of directors, which will consider the performance of the Company, its financial condition, future investment opportunities and other factors as our majority shareholder and the board of directors deems appropriate.

Capital Markets and Impact on Liquidity. During 2012 and 2011, we accessed the capital markets for our 8.50% Senior Notes and renewed our revolving bank credit facility arrangement in 2011 as described above. In 2012 and 2011, the U.S. financial markets were not adversely affected by the events in the international markets, including the financial crisis that has threatened the various countries in the Euro zone. Such crisis had an impact on European banks that had exposure to these countries which could ultimately impact borrowers in the United States. Currently, the Euro zone financial markets appear to have stabilized, but the underlying cause of certain countries’ high debt levels may take years to reduce their risk profile. The longer-term outlook could be impacted from these or other international events. At this time, we do not have current plans to obtain additional financing in 2013, but this situation could change depending on a number of factors, such as acquisition opportunities and prices of oil and natural gas.

A fairly recent example of scarce financing availability occurred in 2009 when the global financial markets and economic conditions were severely distressed. There were concerns of bank failures and liquidity concerns whether our banks would be able to meet their commitments under credit arrangements in place during that time. In addition, prices for oil and natural gas had decreased from 2008. These conditions contributed to fewer financing transactions being completed.

Asset retirement obligations. Each year (or more often if conditions warrant) we review, and to the extent necessary, revise our ARO estimates. Our ARO at December 31, 2012 and 2011 were $384.1 million and $393.9 million, respectively. In 2012, we revised our estimate to account for the increased cost to comply with new regulations including an increase in work scope and interpretation of work scope. See Financial Statements – Note 5 – Asset Retirement Obligations under Part II, Item 8 of this 10-K for additional information regarding our estimation of our ARO.

Contractual obligations. The following table summarizes our significant contractual obligations by maturity as of December 31, 2012. At December 31, 2012, we did not have any capital leases.


	Payments Due by Period at December 31, 2012
	Total		Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years
	(Dollars in millions)
Long-term debt – principal	$	1,070.0	$	—	$	170.0	$	—	$	900.0
Long-term debt – interest (1)		512.6		84.4		163.8		153.0		111.4
Drilling rigs		36.5		36.5		—		—		—
Operating leases		13.1		1.2		2.6		2.6		6.7
Asset retirement obligations		384.1		92.6		97.9		48.3		145.3
Derivatives (2)		9.4		9.4		—		—		—
Other liabilities (3)		5.5		—		5.5		—		—

	$	2,031.2	$	224.1	$	439.8	$	203.9	$	1,163.4

(1)

Interest on long-term debt is comprised of: (a) interest on our 8.50% Senior Notes, which bear interest at a fixed rate of 8.50% and (b) interest on our revolving bank credit facility, which has a variable interest rate, estimated using the borrowings outstanding as of December 31, 2012, an annual interest rate of 3.0%, which was the interest rate as of December 31, 2012, and the commitment fee of 0.5% on the unused balance as of December 31, 2012. Interest was calculated through the stated maturity date of the related debt.

(2)	The amounts for the derivative contracts reported above are the unrealized fair values liability as of December 31, 2012. Actual payments at the settlement date could vary significantly from these amounts.

(3)

We have excluded security requirements pursuant to the Purchase and Sale agreement with Total E&P for the ARO on certain properties as we plan to utilize bonds, not cash, to fulfill the requirements. Further, if cash were to be deposited in escrow, the funds would be returned when the plugging and abandonment work has been completed. A similar rationale was applied to exclude the potential additional security requirements pursuant to the Purchase and Sale agreement with Shell. See Financial Statements – Note 16 – Commitments under Part II, Item 8 of this 10-K for additional information.

Inflation and Seasonality

Inflation. For 2012, our realized prices (unhedged) for oil decreased 1.5%, NGLs decreased 28.8% and natural gas decreased 28.6% from 2011. These are discussed in the Overview section above. Costs measured on a $/Mcfe basis increased by 6.2% in 2012 compared to 2011. The cost per Mcfe is impacted by factors other than cost changes, such as work activity including workovers, production levels and insurance reimbursements. Historically, costs for goods and services have moved directionally with the price of oil, NGLs and natural gas, as these commodities affect the demand for these goods and services. In recent years, other factors have influenced the cost of goods and services. For example, in 2009, some offshore third-party contractors were in high demand associated with remediation work related to Hurricane Ike which increased the price for these types of contractors. In 2010, prices for offshore third-party contractors were relatively stable as drilling activity was curtailed due to the moratorium, but boat prices and other services escalated due to contract work for BP in connection with the cleanup effort from the oil spill at the Macondo well. Other costs, such as insurance premiums, have fluctuated with changes in hurricane activity, the oil spill at the BP Macondo well and other factors besides production volumes. More recently, many commodity prices, including oil, copper, steel and other types of metals, have fluctuated wildly with various world events. Some of this fluctuation is due to strong economic activity in certain parts of the world while other changes appear to be driven by political events around the world, the weak US dollar and other foreign currencies. Also, inflation is impacted as a result of record federal deficits and expectations that large deficits will continue.

Seasonality. Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months. However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. Seasonal weather changes affect our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which require us to evacuate personnel and shut-in production until the storm subsides. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delaying sales of our oil and natural gas.

Critical Accounting Policies

This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with GAAP in the United States. The preparation of our financial statements requires us to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our estimates on historical experience and other sources that we believe to be reasonable at the time. Changes in the facts and circumstances or the discovery of new information may result in revised estimates and actual results may vary from our estimates. Our significant accounting policies are detailed in Financial Statements – Note 1 – Significant Accounting Policies under Part II,

Item 8 in this Form 10-K. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.

Revenue recognition. We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers under short-term contracts (less than 12 months) at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from our net revenue ownership interest in field production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. If oil and natural gas prices decrease, we may need to increase this liability. Also, disputes may arise as to volume measurements and allocation of production components between parties. These disputes could cause us to increase our liability for such potential exposure. We do not record receivables for those properties in which the Company has taken less than its ownership share of production which could cause us to delay recognition of amounts due us.

Full-cost accounting. We account for our investments in oil and natural gas properties using the full-cost method of accounting. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and gas properties are capitalized. Capitalization of geological and geophysical costs, certain employee costs and G&A expenses related to these activities is permitted. We amortize our investment in oil and natural gas properties, capitalized ARO and future development costs (including ARO of wells to be drilled) through DD&A, using the units-of-production method. The units-of-production method uses reserve information in its calculations. The cost of unproved properties related to acquisitions are excluded from the amortization base until it is determined that proved reserves exist or until such time that impairment has occurred. We capitalize interest on unproved properties that are excluded from the amortization base. The costs of drilling non-commercial exploratory wells are included in the amortization base immediately upon determination that such wells are non-commercial. Under the full-cost method, sales of oil and natural gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized unless an adjustment would significantly alter the relationship between capitalized costs and the value of proved reserves.

Our financial position and results of operations may have been significantly different had we used the successful-efforts method of accounting for our oil and natural gas investments. GAAP allows successful-efforts accounting as an alternative method to full-cost accounting. The primary difference between the two methods is in the treatment of exploration costs, including geological and geophysical costs, and in the resulting computation of DD&A. Under the full-cost method, which we follow, exploratory costs are capitalized, while under successful-efforts, the cost associated with unsuccessful exploration activities and all geological and geophysical costs are expensed. In following the full-cost method, we calculate DD&A based on a single pool for all of our oil and natural gas properties, while the successful-efforts method utilizes cost centers represented by individual properties, fields or reserves. Typically, the application of the full-cost method of accounting for oil and natural gas properties results in higher capitalized costs and higher DD&A rates, compared to similar companies applying the successful efforts method of accounting.

DD&A can be affected by several factors other than production. The rate computation includes estimates of reserves which requires significant judgments and is subject to change at each assessment. The determination of when proved reserves exist for our unproved properties requires judgment, which can affect our DD&A rate. Also, estimates of our ARO and estimates of future development costs require significant judgment. Actual results may be significantly different from these estimates, which would affect the timing of when these expenses would be recognized in DD&A. See Oil and natural gas reserve quantities and Asset retirement obligations below for more information.

Impairment of oil and natural gas properties. Under the full cost method of accounting, we are required to periodically perform a “ceiling test,” which determines a limit on the book value of our oil and natural gas

properties. Any write downs occurring as a result of the ceiling test impairment are not recoverable or reversible in future periods. We did not have a ceiling test impairment in 2012, 2011 or 2010, but we did have ceiling test impairments in 2009 and in 2008 as a result of the significant decline in both oil and natural gas prices that began in the second half of 2008. Declines in oil and natural gas prices after December 31, 2012 may require us to record additional ceiling test impairments in the future.

Oil and natural gas reserve quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of DD&A and impairment assessment of our oil and natural gas properties. We make changes to DD&A rates and impairment calculations in the same period that changes to our reserve estimates are made. Our proved reserve information as of December 31, 2012 included in this Form 10-K was estimated by our independent petroleum consultant, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The accuracy of our reserve estimates is a function of:

•

the quality and quantity of available data and the engineering and geological interpretation of that data;

•

estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of which may vary considerably from actual results;

•

the accuracy of various mandated economic assumptions such as the future prices of oil and natural gas; and

•

the judgment of the persons preparing the estimates.

Insurance receivables. We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Actual collections may be significantly different than these estimates and revisions could impact our lease operating expense, our oil and natural gas property balance and our DD&A rates.

Asset retirement obligations. We have significant obligations to plug and abandon all well bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations are primarily associated with plugging and abandoning wells, removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating the future restoration and removal cost is difficult and requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially affect our estimates of these future costs from period to period. Pursuant to the Asset Retirement and Environmental Obligations topic of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (the “Codification”), we are required to record a separate liability for the discounted present value of our ARO, with an offsetting increase to the related oil and natural gas properties on our balance sheet.

Inherent in the present value calculation of our liability are numerous estimates and judgments, including the ultimate settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and changes in the legal, regulatory, environmental and political environments. Revisions to these estimates impact the value of our abandonment liability, our oil and natural gas property balance and our DD&A rates.

Fair value measurements. We measure the fair value of our derivative financial instruments by applying the income approach and using inputs that are derived principally from observable market data. Changes in the

underlying commodity prices of the derivatives impact the unrealized and realized gain or loss recognized. We do not apply hedge accounting to these derivatives, therefore the change in fair value for all outstanding derivatives, which include derivatives that are hedges against future production, are reflected currently in our statement of income. This can create timing differences between when the production is recognized and when the gain or loss on the derivative is recognized in the income statement.

Income taxes. We provide for income taxes in accordance with the Income Taxes topic of the Codification, which requires the use of the liability method of computing deferred income taxes, whereby deferred income taxes are recognized for the future tax consequences of the differences between the tax basis of assets and liabilities and the carrying amount in our financial statements required by GAAP. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Because our tax returns are filed after the financial statements are prepared, estimates are required in recording tax assets and liabilities. We record adjustments to reflect actual taxes paid in the period we complete our tax returns. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

We recognize uncertain tax positions in our financial statements when it is more likely than not that we will sustain the benefit taken or expected to be taken. When applicable, we recognize interest and penalties related to uncertain tax positions in income tax expense. The final settlement of these tax positions may occur several years after the tax return is filed and may result in significant adjustments depending on the outcome of these settlements.

Share-based compensation. In accordance with the Compensation – Stock Compensation topic of the Codification, we recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of the grant. We estimate forfeitures during the service period and make adjustments depending on actual experience. These adjustments can create timing differences on when expense is recognized.

Accounting Policies and Pronouncements

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks arising from fluctuating prices of crude oil, natural gas and interest rates as discussed below. We have utilized derivative contracts to reduce the risk of fluctuations in commodity prices and expect to use these instruments in the future. We are currently a party to derivative contracts for oil.

Commodity price risk. Our revenues, profitability and future rate of growth substantially depend upon market prices for oil, NGLs and natural gas, which fluctuate widely. Oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. For example, assuming a 10% decline in our average realized oil, NGLs and natural gas sales prices in 2012, our income before income taxes would have decreased by approximately 71% in 2012. If costs and expenses of operating our properties had increased by 10% in 2012, our income before income taxes would have decreased by 21% in 2012.

As of December 31, 2012, we had derivative contracts for oil with a notional quantity of 2.0 MMBbls and various termination dates in 2013 and 2014. We do not designate our commodity derivative contracts as hedging instruments. While these derivative contracts are intended to reduce the effects of volatile oil prices, they may also limit future income from favorable price movements. For additional details about our derivative contracts, refer to Financial Statements – Note 6 – Derivative Financial Instruments under Part II, Item 8 of this Form 10-K.

Interest rate risk. As of December 31, 2012, we had $170.0 million outstanding on our revolving bank credit facility and during 2012 we had amounts outstanding that ranged from zero to $330.0 million. The revolving bank credit facility has a variable interest rate which is primarily impacted by the rates for the LIBOR and the margin ranges from 2.0% to 2.75% depending on the amount outstanding. In 2012, if interest rates would have been 100 basis points higher (an additional 1%); our interest expense would have been approximately $1.0 million higher. We did not have any derivative contracts related to interest rates as of December 31, 2012.

Item 8.

Financial Statements and Supplementary Data

W&T OFFSHORE, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Management’s Report on Internal Control over Financial Reporting		76
Report of Independent Registered Public Accounting Firm		77
Report of Independent Registered Public Accounting Firm		78

Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2012 and 2011		79
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010		80
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2012, 2011 and 2010		81
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010		82
Notes to Consolidated Financial Statements		83

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 in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States (GAAP). Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated 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. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2012 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of W&T Offshore, Inc. and Subsidiaries

We have audited W&T Offshore, Inc. and subsidiaries’ 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). W&T Offshore, Inc. and subsidiaries’ 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.

In our opinion, W&T Offshore, Inc. and subsidiaries 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 W&T Offshore, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012 of W&T Offshore, Inc. and subsidiaries and our report dated February 27, 2013 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 27, 2013

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

W&T Offshore, Inc. and Subsidiaries

We have audited the accompanying consolidated balance sheets of W&T Offshore, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, changes in shareholders’ equity, and cash flows 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 W&T Offshore, Inc. and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their 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), W&T Offshore, Inc. and subsidiaries’ 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

Houston, Texas

February 27, 2013

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2012			2011
	(In thousands, except share data)
Assets
Current assets:
Cash and cash equivalents	$	12,245		$	4,512
Receivables:
Oil and natural gas sales		97,733			98,550
Joint interest and other		56,439			25,804
Income tax receivable		47,884			—

Total receivables		202,056			124,354
Deferred income taxes		267			2,007
Prepaid expenses and other assets		25,555			30,315

Total current assets		240,123			161,188
Property and equipment – at cost:
Oil and natural gas properties and equipment (full cost method, of which $123,503 at December 31, 2012 and $154,516 at December 31, 2011 were excluded from amortization)		6,694,510			5,959,016
Furniture, fixtures and other		21,786			19,500

Total property and equipment		6,716,296			5,978,516
Less accumulated depreciation, depletion and amortization		4,655,841			4,320,410

Net property and equipment		2,060,455			1,658,106
Restricted deposits for asset retirement obligations		28,466			33,462
Other assets		19,943			16,169

Total assets	$	2,348,987		$	1,868,925

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	123,885		$	75,871
Undistributed oil and natural gas proceeds		37,073			33,732
Asset retirement obligations		92,630			138,185
Accrued liabilities		20,755			29,705
Income taxes payable		266			10,392

Total current liabilities		274,609			287,885
Long-term debt, less current maturities		1,087,611			717,000
Asset retirement obligations, less current portion		291,423			255,695
Deferred income taxes		145,249			58,881
Other liabilities		8,908			4,890
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.00001 par value, 20,000,000 shares authorized and 0 issued at December 31, 2012 and $0.00001 par value, 2,000,000 shares authorized and 0 issued at December 31, 2011		—			—
Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,118,803 issued and 75,249,630 outstanding at December 31, 2012; 77,220,706 issued and 74,351,533 outstanding at December 31, 2011;		1			1
Additional paid-in capital		396,186			386,920
Retained earnings		169,167			181,820
Treasury stock, at cost		(24,167	)		(24,167	)

Total shareholders’ equity		541,187