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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

Form 10-K

For the fiscal year ended December 31, 2004

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 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 ¨ No þ

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 an accelerated filer. Yes ¨ No þ

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $310,027,000 based on the closing sale price of $20.42 per share as reported by the New York Stock Exchange on March 29, 2005.

The number of shares of the registrant’s common stock outstanding on March 30, 2005 was 65,969,024.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders to be held May 26, 2005 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 Litigation Securities Reform Act of 1995 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 “Factors That Could Affect Future Results” in Item 7A of this Annual Report and may be discussed from time to time in our reports filed with the Securities and Exchange Commission subsequent to this report. We assume no obligation, nor do we intend, to update these forward-looking statements.

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PART I

Items 1. and 2. Business and Properties

Unless the context requires otherwise, references in this Annual Report to “W&T,” “we,” “us” and “our” refer to W&T Offshore, Inc. and its consolidated subsidiaries. We are an independent oil and natural gas acquisition, exploitation and exploration company. We are focused primarily in the Gulf of Mexico area, where we have developed significant technical expertise and where the high production rates associated with hydrocarbon deposits have historically provided us the best opportunity to achieve a rapid payback on our invested capital. We have leveraged our historic experience to focus on higher impact capital projects in the Gulf of Mexico, including the deepwater (water depths in excess of 500 feet) and the deep shelf (well depths in excess of 15,000 feet).

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum consultants, our proved reserves at December 31, 2004 were 467.5 Bcfe. We calculate that our proved reserves had a PV-10 of $1.5 billion and a standardized measure of after-tax discounted cash flows of $974.8 million as of December 31, 2004. Of those reserves, 62% were proved developed reserves and 49% were natural gas reserves.

We grow our reserves through drilling programs and acquisitions. Some of our acquisitions are made through the exercise of preferential rights in properties in which we already own an interest. During 2004, we exercised preferential rights to purchase on five such properties. The costs of exercising our preferential rights totaled $32.5 million and added approximately 19.2 Bcfe of proved reserves. We have focused on acquiring properties where we can develop an inventory of drilling prospects that enable us to continue to add reserves post-acquisition. During 2003 and 2002, we made significant acquisitions from ConocoPhillips and Burlington Resources, Inc., respectively. During 2004, we did not complete any significant acquisition. In spite of the extremely competitive nature of the current acquisition landscape, our acquisition team is working diligently to find properties that fit our historical profile and will add strategic and financial value to the Company.

For the year ended December 31, 2004, capital expenditures of $284.8 million included $90.7 million for development activities, $150.4 million for exploration and $43.7 million for other capital items including acquisitions. These expenditures do not include any amount of allocated general and administrative expenses or interest. Our capital expenditures for the year ended December 31, 2004 were primarily financed by net cash flow provided by operating activities. We participated in the drilling of 32 exploratory wells and seven development wells of which 26 were on the conventional shelf and land, four were deep shelf wells and nine were in the deepwater. All of the development wells were successful. Of the 32 exploration wells, 21 were successful and five of the successful wells are in the deepwater. We operate a total of 16 of the 21 successful exploratory wells, including four wells that we operate in the deepwater. During the three-year period ended December 31, 2004, we drilled 52 exploratory wells, of which 37 were successful (which we define as completed or planned for completion).

During 2005, we expect to spend $266 million on capital projects and $42 million on plug and abandonments, major maintenance and expense workovers. During 2005, we anticipate drilling 30 exploratory wells and five or more development wells.

We have become more active in bidding for Gulf of Mexico leases on the outer continental shelf (“OCS”) at lease sales conducted by the U.S. government through the Minerals Management Service (“MMS”). At the March 2004 OCS lease sale, the MMS awarded us leases for a 100% working interest in seven OCS blocks located in the central Gulf of Mexico, three of which are in the deepwater. At the August 2004 OCS lease sale, the MMS has awarded us leases for a 100% working interest in six OCS blocks located in the western Gulf of Mexico, four of which are in the deepwater. We were high bidder on nine of the 15 bids that we submitted at the March 2005 OCS lease sale. High bids are subject to MMS evaluation, which will occur within 90 days of the sale.

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Business Strategy

We plan to continue to acquire and exploit reserves on the OCS of the Gulf of Mexico, 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 our opportunities for deepwater exploration have been enhanced by technological advances in recent years that enable the connection of subsea wells to existing infrastructure over longer distances, eliminating the requirement for new, dedicated production facilities, the installation of which requires long lead times and large capital investments. We also believe asset divestitures and resource constraints of major integrated oil companies and other large upstream companies may allow us to acquire attractive deepwater prospects at favorable prices with a significant portion of the up-front development expenses, such as infrastructure and seismic, already invested.

We believe a significant portion of our acreage has exploration potential below currently producing zones, including deep shelf reserves. We consider deep shelf targets to be hydrocarbon-bearing horizons located in shallow water areas of the Gulf of Mexico 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 and recent royalty suspension incentives from the MMS should partially offset higher drilling costs.

We believe our conservative financial approach has contributed to our success and has positioned us to capitalize on new opportunities as they develop. We have typically relied solely on net cash provided by operating activities and traditional commercial bank credit facilities to fund our growth. We have historically limited annual capital spending for exploration, exploitation and development activities to net cash provided by operating activities and typically used our bank credit facility for acquisitions and to balance working capital fluctuations.

In the future, as we further expand our operations into the higher impact deepwater and deep shelf areas of the Gulf of Mexico, our capital spending may exceed net cash provided by operating activities, in which event we may issue debt or equity securities to fund such future expenditures.

Proved Reserves

Of our 467.5 Bcfe of proved reserves at December 31, 2004, 62% were proved developed and 49% were natural gas. Our estimates of proved reserves were based on a reserve report prepared by Netherland, Sewell & Associates, Inc., our independent petroleum consultants, and the reserve amounts are consistent with filings we make with federal agencies.

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Our proved reserves as of December 31, 2004 are summarized in the table below.

Production

During 2004, our net production averaged approximately 225 MMcfe per day with approximately 4 MMcfe per day temporarily shut in as a result of Hurricane Ivan. See “Factors That Affect Future Results”—Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses beginning at page 33 for a further discussion of the effect of Hurricane Ivan on our business.

Properties

The majority of our fields are 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 table describes our ten largest fields as of December 31, 2004. At December 31, 2004, these fields accounted for approximately 60% of our PV-10 value, or $942.5 million (before plug and abandonment cost), and had proved reserves totaling 281 Bcfe.

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The following table describes our successful exploratory wells that were drilled in 2004, and their estimated cost as of December 31, 2004 (dollars in millions).

Acreage

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2004. Net acreage is our percentage ownership of gross acreage. Deepwater refers to acreage in over 500 feet of water.

Approximately 81% 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 approximately the same amount of our acreage as is held-by-production.

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Production History

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

Productive Wells

The following table presents our ownership at December 31, 2004 of our productive oil and natural gas wells. A net well is our percentage working interest of a gross well.

Drilling Activity

Development and Exploration Drilling

The following table sets forth the results of our total drilling activities for the last three years.

Exploration Drilling

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

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Current Drilling Activity

We were in the process of drilling 4 gross (2.5 net) exploration wells as of March 29, 2005.

Oil and Natural Gas Marketing and Delivery Commitments

We sell our oil and natural gas through various marketing companies. We are not dependent upon, or confined to, any one purchaser or small group of purchasers. However, we currently sell over 10% of our production to each of the following companies: BP Amoco, Shell Trading and ConocoPhillips. Due to the nature of oil and natural gas markets and because oil and natural gas are 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.

Employees

As of December 31, 2004, we employed 133 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.

Competition

The oil and natural gas industry is highly competitive. Our oil and natural gas business competes for the acquisition of oil and natural gas properties, primarily on the basis of the price to be paid for such properties, with numerous entities, including major 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 give 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 complete successfully our business strategy. See “Factors That Could Affect Future Results—Competition for oil and natural gas properties 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” beginning at page 32.

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

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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 Texas Railroad Commission has been changing its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. 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 we will be affected by any action taken materially differently than other natural gas producers with which we compete.

The Outer Continental Shelf Lands Act (“OCSLA”), which FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on 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.

Although the FERC has historically imposed light-handed regulation on offshore facilities that meet its traditional test of gathering status, it has the authority to exercise jurisdiction under the OCSLA over gathering facilities, if necessary, to permit non-discriminatory access to service. In an effort to heighten its oversight of the OCS, the FERC recently attempted to promulgate reporting requirements for all OCS “service providers,” including gatherers, but the regulations were struck down as ultra vires by a federal district court, which decision was affirmed by the U.S. Court of Appeals in October 2003. The FERC withdrew its regulations in March 2004. Subsequently, in April 2004, the MMS initiated an inquiry into whether it should amend its regulations to assure that pipelines provide open and non-discriminatory access over OCS pipeline facilities. For 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 are generally regulated by the FERC under the NGA and NGPA, as well as the OCSLA.

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; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Federal leases. A substantial portion of our operations is located on federal oil and natural gas leases, which are administered by the MMS pursuant to the OCSLA. These leases are issued through 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. 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. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plug and abandonment of wells located offshore and the installation and removal of all production facilities.

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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 currently rely on arm’s-length sales prices and spot market prices as indicators of value. On August 20, 2003, the MMS issued a proposed rule that would change certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The proposed changes include changing the valuation basis for transactions not at arm’s-length from spot to the New York Mercantile Exchange prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. Final comments on the proposed rule were due on November 10, 2003. We cannot predict whether this proposed rule will take effect as written, nor can we predict whether the proposed rule, if it takes effect, will be challenged in federal court and whether it will withstand such a challenge. We believe this rule, as proposed, will not have a material impact on our financial condition, liquidity or results of operations.

Oil and natural gas liquids transportation rates. Sales of crude oil, condensate and natural gas liquids by us are not currently regulated and are made 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.

The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC’s regulation of natural gas pipelines under the Natural Gas Act. Regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, issued in October 1993, the FERC implemented regulations generally grandfathering all previously unchallenged interstate pipeline rates and made these rates subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge a market-based rate if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. As provided for in Order No. 561, in July 2000, the FERC issued a Notice of Inquiry seeking comment on whether to retain or to change the existing oil rate-indexing method. In December 2000, the FERC issued an order concluding that the rate index reasonably estimated the actual cost changes in the pipeline industry and should be continued for another five-year period, subject to review in July 2005. In February 2003, on remand of its December 2000 order from the D.C. Circuit, the FERC changed the rate indexing methodology to the Producer Price Index for Finished Goods, but without the subtraction of 1% as had been done previously. The FERC made the change prospective only, but did allow oil pipelines to recalculate their maximum ceiling rates as though the new rate indexing methodology had been in effect since July 1, 2001. A challenge to FERC’s remand order was denied by the D.C. Circuit in April 2004.

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With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been 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.

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 production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition 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 cost without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.

We believe 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 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 may be 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 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 usually are regulated by state law. Other wastes handled at exploration and production sites or used 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,

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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 cost, as well as the oil and natural gas industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.

Our operations are also subject to the Clean Air Act (“CAA”) and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. 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 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 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. 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 and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for 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. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

In November 2003, the EPA’s general wastewater permit for the western portion of the Gulf of Mexico expired. Recently, the EPA re-issued a new wastewater permit to become effective in November 2004. In the interim time period since the expiration of the permit, only those operations that were previously covered by the general permit at the time of its termination were allowed to continue discharging wastewater under an administrative extension of the permit. The EPA did not allow new operators to submit applications for coverage under the old permit.

In 2004, we transferred some properties and their corresponding discharge permits from our subsidiaries to the parent company. This permit transfer process involved canceling the existing permit of the subsidiary and applying for new coverage by the parent simultaneously. The EPA acted on the cancellation, but did not act on the application, citing the expiration of the general permit. We were informed by the EPA of this action several months later. We immediately ceased discharges under the affected permit and requested coverage under an EPA proposed alternative. Accordingly, we requested coverage under an Administrative Compliance Order until such time as the general permit is re-issued.

The EPA has advised that it will consider this Administrative Compliance Order to be diligent prosecution and that operators who apply for and comply with the Administrative Compliance Order, and the terms and conditions of the 1998 general permit, will be considered by the EPA to have only minor paperwork violations, in accordance with the 1995 Clean Water Act Settlement Policy.

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, establishes a regulatory framework for underground injection, with the main goal being the protection of usable

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aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and 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 various 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.

Federal Lease Stipulations address the reduction of potential taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). MMS permit approvals will be conditioned on collection and removal of debris resulting from activities related to exploration, development and production of offshore leases. MMS has issued Notices to Lessees and Operators (“NTL”) 2003-G06 advising of requirements for posting of signs in prominent places on all vessels and structures.

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 we wish to develop, 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 the 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 Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the 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 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.

We maintain insurance against “sudden and accidental” occurrences, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain will 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 all such cost or that such insurance will be available at a cost that would justify its

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purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.

Regulation of oil and natural gas exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, 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, plug and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties.

State regulation. Most states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.

Item 3. Legal Proceedings

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.

Item 4. Submission of Matters to a Vote of Security Holders

Not applicable.

Item 4A. Executive Officers of the Registrant

The following table lists our executive officers:

Tracy W. Krohn has served as Chief Executive Officer and President since he founded the Company in 1983, as Chairman since 2004 and as Treasurer since 1997. Mr. Krohn’s mother is married to Jerome F. Freel.

Jerome 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 joined the Company as Vice President of Finance in 1999 and he has been the Chief Financial Officer since 2000. He is also our Assistant Secretary.

Jeffrey M. Durrant has been a member of our management team since 1997, initially as Geological Manager until 1999, then Exploration Manager until 2001 and, since 2001, Vice President of Exploration.

Joseph P. Slattery joined the Company in November 2002 as our Vice President of Operations. For more than eight years prior thereto, he was a major shareholder and president of Crescent Drilling & Production, Inc., a private consulting engineering firm specializing in total project management and field operations.

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PART II

On January 28, 2005, certain shareholders of our common stock sold 12,655,263 shares pursuant to a registration statement that we filed with the Securities and Exchange Commission (“SEC”) at an initial public offering price of $19.00 per share. Our common stock is listed and principally traded on the New York Stock Exchange under the symbol “WTI”. From January 28, 2005 through March 24, 2005, the high and low closing sale prices per share of our common stock were $22.05 and $18.19, respectively. As of March 14, 2005, there were 56 registered holders of our common stock and approximately 3,400 beneficial shareholders. On March 24, 2005, the last reported closing sale price of our common stock on the New York Stock Exchange Composite Tape was $21.36 per share.

Dividends

Under the second amended and restated credit facility that we entered into on March 15, 2005, we are allowed to pay annual dividends of up to $30 million if we meet certain financial tests and are not in default. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” beginning at page 23 for more information regarding our credit facility.

The following table shows the frequency and amounts of all cash dividends distributed to shareholders during the two most recent fiscal years (in thousands, except per share data).

On March 28, 2005, the Company’s board of directors declared a cash dividend of $0.02 per share of common stock, payable on May 2, 2005 to shareholders of record on April 15, 2005.

Additional Information. Since our initial public offering in January 2005, we are now required to 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 will be available free of charge to the general public through our website at www.wtoffshore.com. These reports will be accessible on our website as soon as reasonably practicable after being filed with the SEC. Requests for copies of this Annual Report and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., Eight Greenway Plaza, Suite 1330, Houston, Texas 77046 or by calling (713) 297-8024. These reports are also available at the SEC’s public reference room at 450 Fifth Street, NW, Washington, DC 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 informational statements and other information regarding issuers that file electronically with the SEC.

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Item 6. Selected Consolidated Financial Data

SELECTED HISTORICAL FINANCIAL INFORMATION

The selected historical financial information set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with our consolidated financial statements and notes to those financial statements included elsewhere in this report. The consolidated statement of income information for the years ended December 31, 2004, 2003, 2002, 2001 and 2000 and the consolidated balance sheet information as of December 31, 2004, 2003, 2002, 2001 and 2000 were derived from our audited financial statements. Share and per share information in this annual report gives effect to a 6.669173211-for-one split of our common stock effective November 30, 2004.

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HISTORICAL RESERVE AND OPERATING INFORMATION

The following table presents summary information regarding our estimated net proved oil and natural gas reserves as of December 31, 2004, 2003, 2002, 2001 and 2000 and our historical operating data for the years ended December 31, 2004, 2003, 2002, 2001, 2000. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC and, except as otherwise indicated, give no effect to federal or state income taxes. For additional information regarding our reserves, please read the section of this report entitled “Items 1. and 2. Business and Properties” beginning at page 1. The selected historical operating data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report.