W&T OFFSHORE INC - Annual Report: 2007 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 2007

or

For the transition period from              to             

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

(713) 626-8525

(Registrant’s telephone number, including area code)

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

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 þ  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 þ

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 þ  No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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.    þ

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

Large accelerated filer þ       Accelerated filer ¨       Non-accelerated filer ¨       Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company. Yes ¨ No þ

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $812,018,198 based on the closing sale price of $27.99 per share as reported by the New York Stock Exchange on June 29, 2007.

The number of shares of the registrant’s common stock outstanding on February 15, 2008 was 76,173,459.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders to be held May 5, 2008 are incorporated by reference into Part III of this Form 10-K.

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W&T OFFSHORE, INC.

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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 and Exchange Act of 1934 that 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 in the circumstances. Certain factors that may affect our financial condition and results of operations are discussed in Item 1A. “Risk Factors” and 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. We assume no obligation, nor do we intend, to update these forward-looking statements. 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.

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PART I

We are an independent oil and natural gas producer, active in the acquisition, exploitation, exploration and development of oil and natural gas properties in the Gulf of Mexico 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). We have acquired rights to develop and exploit 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.

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum consultant, our total proved reserves at December 31, 2007 were 638.8 Bcfe. We calculate that our total proved reserves had a present value of estimated future net revenues discounted at 10% (“PV-10”), after considering future cash outflows related to asset retirement obligations and without deducting any future income taxes, of approximately $3.1 billion and a standardized measure of discounted future cash flows of approximately $2.1 billion as of December 31, 2007. Approximately 62% of our reserves were classified as proved developed and 38% were classified as proved undeveloped. Classified by product, 52% of our reserves were natural gas and 48% were oil and natural gas liquids. For additional information about our proved reserves, see Item 2. “Properties – Proved Reserves.”

We seek to increase our reserves through acquisitions and 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. Our acquisition team continues to work diligently to find properties that fit our profile and that we believe will add strategic and financial value to our company.

On December 21, 2007, we entered into an agreement with Apache Corporation (“Apache”) to acquire its interest in Ship Shoal 349 field for $116 million in cash. This field is located off the coast of Louisiana and covers two federal offshore lease blocks, Ship Shoal blocks 349 and 359. The transaction closed on January 29, 2008, with an effective date of January 1, 2008. The final purchase price is subject to post-closing adjustments. The acquisition increased our working interest in this field to 100% from approximately 59%. Based on our December 31, 2007 reserve report, the estimated proved oil and gas reserves acquired were 60.5 Bcfe. The acquisition was funded from cash on hand. For additional details about this transaction, refer to Note 4 to our consolidated financial statements.

On August 24, 2006, we closed the acquisition of a wholly-owned subsidiary of Kerr-McGee Oil & Gas Corporation (“Kerr-McGee”) by merger for approximately $1.1 billion. The properties acquired included interests in approximately 100 fields on 242 offshore blocks spreading across the Western, Central and Eastern U.S. Gulf of Mexico, primarily in water depths of less than 1,000 feet. This transaction was financed through a combination of cash on hand and proceeds from the issuance of our debt and common stock.

For the year ended December 31, 2007, capital expenditures for oil and gas properties of $361.2 million (before dispositions of $1.8 million) included $170.6 million for development activities, $128.9 million for exploration and $61.7 million for seismic, capitalized interest and other leasehold costs. We participated in the drilling of seven exploratory wells and two development wells of which seven were on the conventional shelf, one was on the deep shelf and one was in the deepwater. All of the development wells were successful. Six of the exploratory wells were successful, one of which is in the deepwater. We operate four of the six successful exploratory wells, including the successful exploratory well in the deepwater. During the three-year period ended December 31, 2007, we participated in the drilling of 55 exploratory wells, of which 42 were successful (which we define as completed or planned for completion). For a more detailed discussion of our drilling activity and

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capital expenditures, see Item 2. “Properties – Drilling Activity” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital expenditures.”

During 2008, we anticipate drilling 44 exploratory wells and six development wells and expect that our capital expenditures (excluding acquisitions, which are not included in our budget) will approximate $800 million, $450 million of which is expected to be spent for development activities, $330 million for exploration and $20 million for seismic.

We participated in bidding for Gulf of Mexico leases on the outer continental shelf (“OCS”) at the October 2007 OCS Lease Sale 205 conducted by the U.S. government through the Minerals Management Service (“MMS”). The MMS awarded us leases covering three OCS blocks located on the conventional shelf in the central Gulf of Mexico for a total lease bonus of approximately $1.1 million.

Business Strategy

We plan to continue to acquire and exploit reserves on the OCS, the area of our historical success, or in other areas outside of the Gulf of Mexico that are compatible with our technical expertise and could yield rates of return comparable to those we have historically achieved. 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.

We believe a significant portion of our 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 can be 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.

We believe our financial approach has contributed to our success and has positioned us to capitalize on new opportunities. We typically limit our annual capital spending for exploration, exploitation and development activities to net cash provided by operating activities and use capacity under our credit agreement for acquisitions and to balance working capital fluctuations.

In 2008 our primary focus will be on the conventional shelf. We anticipate drilling 50 wells in 2008, of which 48 will be in water depths of less than 500 feet or from existing platforms.

Competition

The oil and natural gas industry is highly competitive. We are focused primarily in the Gulf of Mexico area and compete for the acquisition of oil and natural gas properties primarily on the basis of the price to be paid 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, which gives them an advantage over us in evaluating and obtaining properties and prospects. 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 Item 1A., “Risk Factors.”

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Oil and Natural Gas Marketing and Delivery Commitments

We sell our oil and natural gas through third-party marketing companies. We are not dependent upon, or contractually limited to, any one purchaser or small group of purchasers. However, in 2007 we sold over 10% of our production to Shell Trading, ConocoPhillips and Chevron. See “Concentration of Credit Risk” in Note 1 to our consolidated financial statements for additional information about our sales to these customers. Due to the nature of oil and natural gas markets and because oil and natural gas are freely traded commodities and there are numerous purchasers in the Gulf of Mexico, we do not believe the loss of a single purchaser or a few purchasers would materially affect our ability to sell our production.

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 natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

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.

Similarly, the natural gas pipeline industry may also be subject to state regulations which may change from time to time. For instance, in response to a legislative directive, the Texas Railroad Commission completed a Natural Gas Pipeline Competition Study in October 2006 and is evaluating whether changes in regulations governing transportation and gathering services provided by intrastate pipelines and gatherers may be necessary. While the changes by these federal and state regulators affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC 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.

The Outer Continental Shelf Lands Act (“OCSLA”), which is administered by the MMS 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.

The MMS recently proposed rules to establish complaint procedures for transporters who believe they have been denied open and non-discriminatory access on OCS pipelines. The MMS has not finalized these rules. For

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those facilities transporting natural gas across the OCS that are not considered to be gathering facilities, the rates, terms and conditions applicable to this transportation continue to be generally regulated by the FERC under the NGA and NGPA, as well as the OCSLA.

In August, 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the NGA to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as W&T, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. The FERC’s rules implementing this provision make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1 million per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas.

In December, 2007, the FERC issued rules requiring that any market participant, including a producer such as W&T, that engages in sales for resale or purchases for resale of natural gas that equal or exceed 2.2 million MMBtus during a calendar year must annually report such sales or 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. These rules are subject to pending requests for rehearing; however, if implemented as currently written, the monitoring and reporting required could increase our administrative costs. We do not anticipate that we will be affected any differently than other producers of natural gas.

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.

Oil and natural gas liquids transportation rates. Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. 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 it affects 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

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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 operations are conducted on federal oil and natural gas leases, which are administered by the MMS pursuant to the OCSLA. These leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed MMS regulations and orders that are subject to interpretation and change by the MMS.

For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. These plans must include certain information on the potential environmental impacts of the lessee’s proposed activities, including wastes and air emissions projected to be generated by the activities, proposed environmental monitoring activities, and potential impacts on marine mammals and endangered and threatened species. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the MMS prior to the commencement of drilling operations. The MMS has promulgated regulations requiring offshore production facilities, structures and producer-operated pipelines located on the OCS to meet stringent engineering, construction and safety specifications. The MMS also restricts the flaring or venting of natural gas and prohibits the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines.

To cover the various obligations of lessees on the OCS, the MMS 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. We are currently exempt from supplemental bonding requirements by the MMS. Under some circumstances, the MMS 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.

The MMS also 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 MMS. The MMS regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases is determined based on the New York Mercantile Exchange prices adjusted for locality and quality differentials. MMS regulations also govern the treatment of transactions under a joint operating agreement.

Environmental regulations. We are subject to stringent federal, state and local 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

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business and consequently affects our profitability. The remediation, reclamation and abandonment of wells, platforms and other facilities are significant costs to us. 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.

The effects of Hurricanes Ivan, Katrina and Rita during the 2004 and 2005 hurricane seasons significantly impacted oil and gas operations on the OCS. The effects included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. The MMS continues 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 MMS has periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. Recommended practices for the use of moored rigs during the hurricane season were issued in 2006 in a Notice to Lessees to ensure that consistent proper site assessments were performed and minimum design return periods were established across the Gulf of Mexico in an effort to decrease the number of moored rig failures during hurricanes. Additional operational enhancements were implemented by MMS during the 2007 Hurricane Season. In 2007, a Notice to Lessees provided guidance to also insure that the design of new OCS platforms and related structures fully considers specific environmental conditions at the platform location in compliance with the requirements of 30 CFR 250.900(a). It is possible that similar, if not more stringent, requirements will be issued by the MMS for the 2008 Hurricane Season. Rig availability may be impacted and therefore may pose a potential impact on our business; however, our competitors will be subject to the same market impacts.

We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, 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 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 oil or 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.

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Our operations are also subject to the Clean Air Act (“CAA”), as amended, 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. 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.

The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), imposes restrictions and controls on the discharge of oil, produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System (“NPDES”) program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters, unless otherwise authorized. In October 2007, the U.S. Environmental Protection Agency (“EPA”) issued a new general NPDES permit applicable to discharges from oil and gas exploration and production activities in the Western Gulf of Mexico. This revised permit contains a requirement to contain maintenance waste such as removed paint and materials associated with surface preparation and coating applications to “the maximum extent practicable to prevent discharge,” which includes a requirement to contain airborne materials such as spent or oversprayed abrasives, paint chips, and paint overspray. The permit also requires that certain recommended practices for containing waste be implemented prior to conducting sandblasting or similar maintenance activities. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Cost may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act, the Oil Pollution Act of 1990 (“OPA90”), and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. In late 2007, a number of federal and state agencies, including the EPA, the Coast Guard, various U.S. Attorney’s Offices in Louisiana, and various Louisiana environmental agencies, entered into a Memorandum of Understanding (“MOU”) to foster compliance with state and federal laws to prevent oil and brine pollution in coastal areas of Louisiana. The execution of this MOU may indicate an increased focus on the enforcement, including criminal enforcement, of water pollution laws against oil and gas operators in coastal Louisiana and may subject our operations in that area to additional regulatory scrutiny. We believe that our operations comply in all material respects with the requirements of the Clean Water Act, OPA90, and state statutes enacted to control water pollution.

Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. The Safe Drinking Water Act of 1974, as amended, established a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus in order to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In Louisiana and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate less than five permitted underground injection wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

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.

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Federal Lease Stipulations address the reduction of potential taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). The MMS also issues numerous Notices to Lessees and Operators (NTLs) that provide formal guidelines on implementation of OCS regulations and standards. Recent NTLs prescribing measures to minimize threats to protected marine species with which we must comply include 2007-G02 Implementation of Seismic Survey Mitigation Measures and Protected Species Observer Program, 2007-G03 Marine Trash and Debris Awareness and Elimination, 2007-GO4 Vessel Strike Avoidance and Injured/Dead Protected Species Reporting, and 2004-G06 Structure Removal Operations, among others. MMS conditions permit approvals on collection and removal of debris resulting from activities related to exploration, development and production of offshore leases.

Certain flora and fauna that have officially been 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 might be required.

Because our oil and natural gas operations include a production platform in the Gulf of Mexico located in a National Marine Sanctuary, we are also subject to additional federal regulation, including by the National Oceanic and Atmospheric Administration (“NOAA”). 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 Oil Pollution Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species 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 and other protected areas, may require certain mitigation measures to avoid harm to wildlife, and 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.

Various pieces of equipment and structures we own have been coated with lead-based paints as was customary in the industry at the time these pieces of equipment were fabricated and constructed. These paints may contain lead at a concentration high enough to be considered a regulated hazardous waste when removed. If we need to remove such paints in connection with maintenance or other activities and they qualify as a regulated hazardous waste, the costs of their disposal would increase. High lead levels in the paint might also require us to institute certain administrative and/or engineering controls required by the Occupational Safety and Health Act and MMS to ensure worker safety during paint removal.

Naturally Occurring Radioactive Materials (“NORM”) contaminate minerals, minerals extraction and processing equipment used in the oil and natural gas industry. The resulting NORM waste 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 law related to NORM waste.

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We maintain insurance covering well control, property and hurricane damage, 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 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 Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Inflation and Seasonality.”

Employees

As of December 31, 2007, we employed 294 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 items with the Securities and Exchange Commission (“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 the SEC. This Annual Report 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 100 F Street, N.E., Room 1580, 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 other information regarding issuers that file electronically with the SEC.

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these 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 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 and natural gas production directly affects our revenues, profitability, access to capital and future rate of growth. Oil 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 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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Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but may also reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We could be adversely affected by a recession in the United States or global economy.

A recessionary economic environment could result in lower demand for oil and natural gas and may also result in less capital available to fund future growth. These factors could negatively impact our profitability or limit our growth.

Hedging transactions may limit our potential gains.

In order to manage our exposure to price risks in the marketing of our oil and natural gas, we may periodically enter into oil and gas price hedging arrangements with respect to a portion of our expected production. For example, in January 2006 we entered into commodity swap and option contracts relating to approximately 14 Bcfe, or 14%, of our production in 2006, 18 Bcfe, or 14%, of our production in 2007 and 11 Bcfe of our anticipated production in 2008. While these contracts are intended to reduce the effects of volatile oil and natural gas prices, they may also limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contracts. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

Refer to Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” and Note 7 to our consolidated financial statements for additional information about our hedging arrangements.

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

Borrowings under the revolving portion of our Third Amended and Restated Credit Agreement, as amended (the “Credit Agreement”) are currently limited to $500.0 million. Availability is determined periodically at the discretion of the banks and is based in part on oil and gas prices and in part on our proved reserves. The Credit Agreement may limit our ability to incur additional indebtedness based on specified financial covenants, ratios or other criteria. Lower oil and gas prices in the future could result in a reduction in availability and also affect our

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ability to satisfy these covenants, ratios or other criteria and thus could reduce our ability to incur additional indebtedness. Lower oil and gas prices, over a sustained period of time and without a corresponding decline in the cost of goods and services necessary to conduct our operations, could affect our ability to replace reserves and thus could reduce our ability to incur additional indebtedness.

As of December 31, 2007, approximately 38% of our total proved reserves were undeveloped and approximately 27% 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.

While we have development plans for exploiting and producing all of our proved reserves, 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 20% of our proved undeveloped and approximately 20% 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.

Relatively short production periods for our 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 and production over time.

Unless we conduct successful development, exploitation and exploration activities 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 vast majority of our current operations are in the Gulf of Mexico. Production from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions of the United States. Our independent petroleum consultant estimates that, on average, 50% of our total proved reserves are depleted within three years. As a result, our need to replace reserves 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 portion of their reserves outside the Gulf of Mexico area. We may not be able to develop, exploit, find or acquire additional reserves to sustain our current production levels or to grow production at the same rates as we have in the past. 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 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 through a combination of cash flows from operations and borrowings under our debt agreements. 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, the sale of production payments 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, prices of oil and gas, and our success in developing and producing new reserves. If revenues were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, our ability to replace our reserves would be reduced. If our cash flow from operations is 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 meet our requirements.

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If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration 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 and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.

Competition for oil and natural gas properties and prospects is intense; some of our competitors have larger financial, technical and personnel resources that 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 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 gas properties. For example, new leases acquired from the MMS 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, exploitation 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 limited 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 detect 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 shallow 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 shelf development costs 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.

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

We are required to record a liability for the discounted present value of our asset retirement obligations to remove our 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 clean up. 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 the future restoration and removal cost in the Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, contracts and regulations often have vague descriptions of what constitutes removal, and asset removal technologies and costs are constantly changing. In 2007 we increased our estimates of future asset retirement obligations as a result of our evaluation of recent increased costs incurred for plugging and abandonment activities in the Gulf of Mexico. We may continue to incur significant additional liabilities for asset retirement in future years.

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

As we carry out our drilling program, we will not serve as operator of all planned wells. As a result, 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 our targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

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 and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure 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 business involves a variety of operating risks, including:

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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:

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, exploitation 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 affecting the Gulf of Mexico specifically.

The geographic concentration of our properties along the Texas and Louisiana 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:

Because all our properties could experience the same condition 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

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properties over a wider geographic area. In 2006, company-wide production was reduced by approximately 7.8 Bcfe because of the carryover effect of Hurricanes Katrina and Rita that occurred in 2005, and in 2005 we were forced to defer company-wide production of approximately 17.4 Bcfe as a result of Hurricanes Cindy, Dennis, Katrina and Rita.

Properties that we purchase 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 a continuing acquisition program. Our recent growth is due in part to 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:

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 not historically inspected every well, platform or pipeline. Even if we had 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 that it created. 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 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 gas properties or businesses. In particular, we will 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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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. It is our current intention to continue focusing on acquiring properties with development and exploration potential located in the Gulf of Mexico area. 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.

If oil 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. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could reduce the total value of our reserves. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Impairment of oil and natural gas properties” for a discussion of the ceiling test.

Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our 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, 2007. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Oil and natural gas reserve quantities” for a discussion of the estimates and assumptions about our estimated oil and natural gas reserves information reported in Item 1. “Business” and Item 2. “Properties.”

In order to prepare our reserve estimates, our independent petroleum consultant projected 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 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 prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

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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 a property in which we own an interest or have operating rights and have what our geoscientists believe, based on available seismic and geological information, to be indications of economic quantities 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 be useful in predicting the characteristics and potential reserves associated with our drilling prospects. To the extent we continue to drill in the deepwater, and as we continue our drilling efforts on deep shelf targets, our drilling activities could become more expensive. In addition, the geological complexity of deepwater and deep shelf formations may make it more difficult for us to sustain our historical rates of drilling success. As a result, there can be no assurance that we will find commercial quantities of oil and natural gas and, therefore, there can be no assurance that we will achieve our targeted rate of return or have a positive rate 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, in some cases 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. In August 2005, all but three of our operated wells were temporarily shut in as a result of Hurricane Katrina and in September 2005, all of our operated wells were temporarily shut in as a result of Hurricane Rita.

In some cases, our wells are tied back to platforms owned by parties who do not have an economic interest in the 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. As of December 31, 2007, nine fields, accounting for 107 Bcfe (or 16.8%) of our total proved reserves, are tied back or are planned to be tied back to separate, third-party host 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.

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

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comply with existing 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:

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

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 gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See Item 1. “Business – Regulation” for a more detailed description 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:

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

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In the past, we have been subject to investigation with respect to allegations that we did not comply with applicable environmental laws and regulations. Resolution of these matters has required considerable management time and expense.

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 or if our operations met previous standards in the industry at the time they were performed. Our permits require that we report any incidents that cause or could cause environmental damages. See Item 1. “Business – Regulation” for a more detailed description of our environmental risks.

We operate a production platform in a National Marine Sanctuary.

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. 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. As of December 31, 2007, fields associated with this platform had proved reserves of approximately 5.9 Bcfe, representing approximately one percent of our total proved reserves.

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, Chief Executive Officer and President; W. Reid Lea, our Executive Vice President and Manager of Corporate Development; John D. Gibbons, our Senior Vice President, Chief Financial Officer and Chief Accounting Officer and Stephen L. Schroeder, our Senior Vice President and Chief Operating Officer, 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 Item 4. “Executive Officers of the Registrant” for more information regarding certain members of our 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 offshore oil and 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 Texas, Louisiana and the Gulf of Mexico, we could be materially and adversely affected because our operations and properties are concentrated in those areas.

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

Substantially all of our accounts receivable result from oil 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

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conditions. In recent years, market conditions resulting in downgrades to credit ratings of energy merchants affected the liquidity of several of our purchasers. We continue to sell oil and natural gas to companies we believe are reasonable credit risks. In some cases, we have required purchasers to post letters of credit or provide other means of support to secure their performance under the purchase contracts.

Our insurance coverage may not be sufficient or may not be available to cover some liabilities or losses that we may incur.

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 operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. 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. In addition, pollution and environmental risks generally are not fully insurable.

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 substantial insurance claims made by oil and gas producers in the Gulf of Mexico as a result of Hurricanes Katrina and Rita in 2005 caused the cost of insurance to rise dramatically between 2005 and 2006. In July 2007, the Company renewed its insurance policy covering well control, property and hurricane damage at a cost of approximately $23.9 million. The policy limits for well control and hurricane damage are $100 million and $150 million, respectively. The cost of this insurance was $4.0 million for the 2005-2006 period and $28.7 million for the 2006-2007 period. Coverage and deductibility limits also changed during this time frame. We are also exposed to the possibility that 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.

During the three-year period ended December 31, 2007, we spent approximately $24.0 million to remediate hurricane damage that was not covered by insurance, all of which related to Hurricanes Katrina and Rita in 2005.

The market price of our common stock could be adversely affected by sales of substantial amounts of our common stock in the public markets and the issuance of shares of common stock in future acquisitions.

Sales of a substantial number of shares of our common stock by us or by other parties in the public market or the perception that such sales may occur could cause the market price of our common stock to decline. In addition, the sale of such shares in the public market could impair our ability to raise capital through the sale of common or preferred stock.

In addition, in the future, we may issue shares of our common stock in connection with acquisitions of assets or businesses. If we use our shares for this purpose, the issuance could have a dilutive effect on the value of your shares, depending on market conditions at the time of an acquisition, the price we pay, the value of the businesses or assets acquired and our success in exploiting the properties or integrating the businesses we acquire and other factors.

Risks Related to Financings

Regardless of our currently outstanding debt, substantial acquisitions and exploitation activities could require additional external capital and could change our risk and property profile.

In order to finance acquisitions of properties and our exploitation activities, we may need to alter or increase our capitalization substantially through the issuance of additional debt or equity securities, the sale of production

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payments or other means. These changes in capitalization may significantly affect our financial risk profile. For instance, in 2006 we entered into a new credit agreement with an initial availability of $987.5 million and we received $307.0 million of net proceeds from the sale of 9,775,000 shares of our common stock, principally in connection with properties acquired by merger in the Kerr-McGee transaction. In 2007, we issued $450 million of 8.25% senior unsecured notes (the “Notes”) subject to the terms of an indenture and amended the Credit Agreement to provide for an increase in the capacity available under our revolving loan facility to $500.0 million from $300.0 million. See Notes 4, 5 and 6 to our consolidated financial statements for additional details about these transactions.

Significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain financing or issue debt or equity securities on acceptable terms for any potential future acquisitions or other transactions.

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 be 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 our debt. Many of these factors, such as oil and 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 debt obligations, we may have to undertake alternative financing plans, such as:

However, 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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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 controls 40,863,307 shares of our common stock, representing approximately 53.6% of our voting interests as of February 15, 2008. As a result, Mr. Krohn has the ability to control the outcome of all matters requiring shareholder approval and other investors, by themselves, will not be able to affect the outcome of any shareholder vote. As a result, Mr. Krohn, subject to any duty owed to our minority shareholders under Texas law, is able to control all matters affecting us, including:

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. As a result, the market price of our common stock could be adversely affected.

Mr. Krohn owns a majority of our common stock, and therefore we are a “controlled company” within the meaning of the rules of the New York Stock Exchange. As such, we are not required to comply with certain corporate governance rules of the New York Stock Exchange 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. Specifically, we are not required to have a majority of independent directors on our board of directors, and we are not required to have nominating and corporate governance and compensation committees composed of independent directors. 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.

None.

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Substantially all of our fields are located in the Gulf of Mexico. These fields are found in water depths ranging from less than ten feet up to 4,200 feet. The reservoirs in our fields are generally characterized as having high porosity and permeability, which typically result in high production rates. The following describes our ten largest fields (based on PV-10 values) as of December 31, 2007. At December 31, 2007, these fields accounted for approximately 53% of our PV-10 value, or $1.8 billion (before estimated asset retirement obligations), and had proved reserves totaling 325 Bcfe.

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On December 31, 2007 we had four fields of major significance (having a PV-10 value that individually approximates or exceeds five percent of our total PV-10 value). These fields were Ship Shoal 349, East Cameron 321, West Cameron 180 and South Timbalier 228. Listed below are descriptions of those properties, all of which are located on the conventional shelf. The PV-10 values referred to below do not give consideration to estimated asset retirement obligations.

Ship Shoal 349 Field. 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 discovered the field in 1993. We initially acquired a 25% working interest in the field from BP 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 took over as operator in December 2004. Cumulative field production through 2007 is approximately 157 Bcfe gross. This field is a sub-salt development with five productive horizons below salt at depths ranging to 17,000 feet. As of December 31, 2007, 21 wells have been drilled, of which 12 wells have been successful. During December 2007, production from this field, net to our interest, averaged 0.9 MMcf of natural gas per day and 639 Bbls of oil per day, or 4.7 MMcfe per day. We are currently exploring several alternatives to increase production including a well stimulation project and evaluation of recently acquired seismic data to further identify exploration and development targets. Ship Shoal 349 is our largest field in terms of reserves and accounted for approximately 15% of our total PV-10 value of proved reserves at December 31, 2007. Total proved reserves associated with our interest in this field were 86.2 Bcfe at December 31, 2007. On December 21, 2007, we entered into an agreement with Apache to acquire its interest in this field for $116 million in cash. The transaction closed on January 29, 2008, with an effective date of January 1, 2008. The final purchase price is subject to post-closing adjustments. We now own a 100% working interest in this field. Based on our December 31, 2007 reserve report, the estimated proved oil and gas reserves acquired were 60.5 Bcfe. For additional details about this transaction, refer to Note 4 to our consolidated financial statements.

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. Cumulative field production through 2007 is approximately 525 Bcfe gross. We own a 100% working interest in the field and are the operator of the field. An 11 well workover and drilling program was commenced in September 2005. The operations on ten wells were successful, resulting in 14 new completions (including four dual completions) in existing field sands. Production from this field was restricted from the fall of 2005 until March 2007 as a result of damage to a third-party gas pipeline caused by the hurricanes in 2005. During December 2007, production from this field, net to our interest, averaged 15.5 MMcf of natural gas per day and 3,008 Bbls of oil per day, or 33.6 MMcfe per day. As of December 31, 2007, East Cameron 321 accounted for approximately 6% of our total PV-10 value and total proved reserves associated with our interest in this field were 25.9 Bcfe.

West Cameron 180 Field. West Cameron 180 field is located approximately 20 miles off the Louisiana coastline in 45 feet of water and includes West Cameron blocks 142, 173, 180, 181, 197, and 198. Tenneco Oil Company discovered this field in 1961. We acquired our ownership in this field primarily through the Kerr-McGee merger transaction. We are the operator of multiple wells in the field (on all of the blocks), and our working interests range from 52.5% to 100%. Since acquiring this field we have drilled one well and our 2008 plans include drilling one exploratory well. The field produces from multiple Miocene aged sands. Cumulative production from this field through 2007 is approximately 1,683 Bcfe gross. During December 2007, production from this field, net to our interest, averaged 11.9 MMcf of natural gas per day and 492 Bbls of oil per day, or 14.9 MMcfe per day. As of December 31, 2007, West Cameron 180 accounted for approximately 5% of our total PV-10 value and total proved reserves associated with our interest in this field were 25.7 Bcfe.

South Timbalier 228 Field. South Timbalier 228 field is located 50 miles off the coast of Louisiana in about 220 feet of water and includes South Timbalier blocks 229 and 230. The field was discovered in November 1994

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by The Louisiana Land and Exploration Company. We acquired South Timbalier block 229 from Burlington Resources and became operator of the field in November 2002. We acquired South Timbalier block 230 in OCS Lease Sale 194, with an effective date of June 2005. We are a 100% working interest owner in this field. We have drilled five wells since becoming operator and our 2008 drilling plan includes a sidetrack in this field. All the producing sands are within the basal Nebraskan section. Cumulative production from this field through 2007 is approximately 24 Bcfe gross. During December 2007, production from this field, net to our interest, averaged 0.6 MMcf of natural gas per day and 483 Bbls of oil per day, or 3.5 MMcfe per day. As of December 31, 2007, South Timbalier 228 accounted for approximately 5% of our total PV-10 value and total proved reserves associated with our interest in this field were 18.8 Bcfe.

The following is a description of the remainder of our top ten properties, of which three are located on the conventional shelf, two are located in the deepwater and one is on the deep shelf. We do not believe that individually any of these properties are of major significance (each has a PV-10 value that is less than five percent of our total PV-10 value, excluding consideration of estimated asset retirement obligations).

Green Canyon 19 Field. Green Canyon 19 field is located off the coast of Louisiana, approximately 150 miles southwest of New Orleans in 750 feet of water. This field covers Green Canyon block 18 and wells drilled from the A-platform located in Green Canyon 18 to Ewing Bank block 988. Mobil Oil Corporation discovered the field in 1982, and ExxonMobil Corporation currently operates the field. We initially acquired a 15% working interest in the field from Burlington Resources in 2002. Our working interest was increased through subsequent transactions with Kerr-McGee and BHP Billiton Petroleum Americas to the current level of approximately 25%. The field produces from multiple Pleistocene and Pliocene sands on the flank of a salt structure. Traps are both structural and stratigraphic. As of December 31, 2007, 47 wells have been drilled of which 39 have been successful. Cumulative field production through 2007 is approximately 643 Bcfe gross. During December 2007, production from this field, net to our interest, averaged 0.6 MMcf of natural gas per day and 475 Bbls of oil per day, or 3.4 MMcfe per day.

Green Canyon 82 Field. Green Canyon 82 field is located approximately 130 miles south-southeast of New Orleans in 2,400 feet of water. We acquired this block in OCS Lease Sale 190 with an effective date of May 2004. As of December 31, 2007, five wells have been drilled in Green Canyon 82. Kerr-McGee drilled and abandoned the first two wells in early 1996. As of December 31, 2007, we have drilled three wells in this field. A total of ten hydrocarbon-bearing zones have been found among the five wells. The primary zones of interest are the 9,450 foot sand (oil), 10,900 foot sand (gas/condensate), 11,200 foot sand (gas/condensate), 11,300 foot sand (oil) and the 12,250 foot sand (oil). We have a 100% working interest in this field. There is no current production from this field and we are currently evaluating our development plan for this field. The three wells that we drilled have been temporarily abandoned and we expect that they will be reentered for completion at a later date after the development plan has been finalized.

High Island 177 Field. High Island 177 field is located off the coast of Texas approximately 20 miles southwest of Galveston in 50 feet of water. The field is contained in a 5,760-acre OCS lease block with a single production platform. The field was discovered by Atlantic Richfield Company in 1988. A total of 11 wells have been drilled to explore and develop high quality reservoir sands between 10,200 feet and 11,400 feet. Cumulative field production through 2007 is approximately 185 Bcfe gross. We acquired a 100% working interest from Vastar Resources, Inc. in 1999. During December 2007, production from this field, net to our interest, averaged 5.9 MMcf of natural gas per day and 28 Bbls of oil per day, or 6.0 MMcfe per day. A new 3-D seismic survey was licensed in 2007 to evaluate the deep shelf exploration potential of this field.

Main Pass 108 Field. Main Pass 108 field contains seven separate OCS blocks, located off the coast of Louisiana approximately 50 miles east of Venice in 50 feet of water. This field includes Main Pass blocks 94, 95, 102, 106, 107, 108 and 109. We acquired our working interests in these blocks, which range from 33% to 100%, in the Kerr McGee merger transaction. 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

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Miocene Big Hum. As of December 31, 2007, 49 wells have been drilled in this field, of which 35 were productive. The Company’s 2008 budget includes several drill locations in this field. Cumulative field production through 2007 is approximately 261 Bcfe gross. During December 2007, production from this field, net to our interest, averaged 17.2 MMcf of natural gas per day and 194 Bbls of oil per day, or 18.4 MMcfe per day.

South Timbalier 41 Field. South Timbalier 41 field is located off the coast of Louisiana south of the Bay Marchand field in approximately 60 feet of water. The field was discovered in 2003, and production commenced the following year. We acquired our 40% working interest from Kerr-McGee in 2006. A series of eleven stacked Miocene pay sands are trapped on the high side of a large growth fault at depths ranging from 15,000 feet to 17,500 feet. A total of nine wells have been drilled of which eight are currently producing. Cumulative field production through 2007 is approximately 89 Bcfe gross. During December 2007, production from this field, net to our interest, averaged 18.5 MMcf of natural gas per day and 737 Bbls of oil per day, or 22.9 MMcfe per day.

West Delta 30 Field. West Delta 30 field is located approximately six miles off the coast of Louisiana in 40 feet of water. Our interests in this field are in West Delta Block 29, which straddles the eastern side of a major piercement salt dome with large accumulations of oil and natural gas sands found in traps along the salt flanks. In 1997, we entered into a farmout agreement with ChevronTexaco to further explore and develop potential reserves. Following a thorough 3-D seismic analysis, we have drilled a total of 17 exploration and development wells, all but one of which have been successful. Our working interests in these wells range from 37.5% to 100%. Cumulative field production through 2007 is approximately 695 Bcfe gross. During December 2007, production from this field, net to our interest, averaged 0.8 MMcf of natural gas per day and 1,024 Bbls of oil per day, or 7.0 MMcfe per day.

Proved Reserves

Our proved reserves at December 31, 2007 totaled 638.8 Bcfe. Approximately 62% of our reserves were classified as proved developed and 38% were classified as proved undeveloped. Classified by product, 52% of our reserves were natural gas and 48% were oil and natural gas liquids. Our estimates of proved reserves were based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum consultant, and the reserve amounts are consistent with filings we make with federal agencies.

Our proved reserves as of December 31, 2007 are summarized below.

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Acreage

The following summarizes gross and net developed and undeveloped acreage at December 31, 2007. Net acreage is our percentage ownership of gross acreage. Deepwater refers to acreage in over 500 feet of water.

Approximately 73% of our total gross acreage is held-by-production, which permits us to maintain all of our exploration, exploitation and development rights (including deep rights below currently producing zones) to the leased area as long as production continues. We have the right to propose future exploration and development projects, including deep exploration projects, on the majority of our acreage.

Approximately 27% of our total gross acreage is undeveloped leasehold. Of our 464,303 total gross undeveloped acres, approximately 49% of our undeveloped leasehold could expire in 2008, 23% in 2009, 12% in 2010, 4% in 2011 and 12% in 2012 and beyond, if not extended by exploration and production activities prior to the applicable lease expiration dates. Our drilling plan for 2008 gives consideration to our undeveloped leasehold that may expire in 2008 to ensure that our valuable lease acreage is explored fully, based on the appropriate technical criteria, before expiration of the lease.

Production

During 2007, our net production averaged approximately 346.7 MMcfe per day.

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Production History

The following presents the historical information about our produced oil and natural gas volumes.

Also refer to Item 6. “Selected Consolidated Financial Data – Historical Reserve and Operating Information” for additional historical operating data.

Productive Wells

The following presents our ownership interest at December 31, 2007 in our productive oil and natural gas wells. A net well is our percentage working interest of a gross well.

Drilling Activity

The following lists our successful exploratory wells that were drilled in 2007 and their estimated cost as of December 31, 2007 (dollars in millions):

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Development Drilling

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

Exploration Drilling

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

Current Drilling Activity

We were in the process of drilling four gross (3.0 net) exploratory wells as of February 15, 2008. The results and our evaluation of this drilling activity have not been completed.

From time to time, we are party to litigation or other legal and administrative proceedings that we consider to be a part of the ordinary course of our business. Currently, 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.

No matters were submitted to a vote of our security holders during the fourth quarter of 2007.

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Executive Officers of the Registrant

The following lists our executive officers:

Tracy W. Krohn has served as Chief Executive Officer and President since he founded the Company in 1983 and as Chairman since 2004. Mr. Krohn’s mother is married to Mr. J.F. Freel.

J.F. Freel has served as a director since our founding in 1983 and Secretary of the Company since 1984. Mr. Freel is married to Mr. Krohn’s mother.

W. Reid Lea has served as the Company’s Executive Vice President and Manager of Corporate Development since September 2005. He joined the Company as Vice President of Finance in 1999 and served as our Chief Financial Officer from 2000 until September 2005.

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 including Executive Vice President and Chief Financial Officer.

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.

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PART II

Our common stock is listed and principally traded on the New York Stock Exchange under the symbol “WTI.” The following sets forth, for each of the periods indicated, the high and low sales price of our common stock as reported on the New York Stock Exchange.

As of February 15, 2008, there were 259 registered holders of our common stock.

Dividends

Under the Credit Agreement, we are allowed to pay annual dividends up to $30.0 million if we meet certain financial tests and are not in default. In addition, the indenture governing the Notes contains restrictions on the payment of dividends unless we meet the restricted payment tests in the indenture. In November 2007, the Credit Agreement was amended to allow for, among other things, a special dividend of up to $30.0 million, to be declared before the end of 2007. On December 3, 2007, our board of directors declared a regular cash dividend of $0.03 per common share and a special cash dividend of $30.0 million, or approximately $0.39 per share, both of which were paid on January 11, 2008 to common shareholders of record on December 21, 2007. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” and Note 6 to our consolidated financial statements for more information regarding our Credit Agreement and the indenture governing the 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):

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With the exception of any 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. On February 25, 2008, our board of directors declared a cash dividend of $0.03 per common share, payable on April 4, 2008 to shareholders of record on March 18, 2008.

Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 in our common stock on the date of our initial public offering (January 28, 2005) and the reinvestment of all dividends thereafter.

Our peer group is comprised of Energy Partners, Ltd., Mariner Energy, Inc., Newfield Exploration Co. and Stone Energy Corp.

Issuer Purchases of Equity Securities

We did not purchase any of our common stock in the open market during the three month period ended December 31, 2007, as the Company does not currently have a stock repurchase program in place. The table below sets forth information about shares delivered by employees to satisfy tax withholding obligations on the vesting of restricted shares.

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SELECTED HISTORICAL FINANCIAL INFORMATION

The selected historical financial information set forth below should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with our consolidated financial statements and notes to those financial statements included elsewhere in this report. The consolidated statement of income information, consolidated cash flow information and the consolidated balance sheet information were derived from our audited financial statements. All share and per share information has been adjusted for the 6.669173211-for-one split of our common stock effective November 30, 2004.

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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 net proved reserves have been made in accordance with the rules and regulations of the SEC and give no effect to federal or state income taxes. For additional information regarding our reserves, please read Item 1. “Business” and Item 2. “Properties.” The selected historical operating data set forth below should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report.