(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   ¨þ

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 whether the registrant has submitted electronically and posted on its corporate website, if any, every interactive data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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 filerþ      Accelerated filer¨      Non-accelerated filer¨      Smaller reporting company¨

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $910,229,000$571,144,000 based on the closing sale price of $26.12$16.37 per share as reported by the New York Stock Exchange on June 30, 2011.2014.

The number of shares of the registrant’s common stock outstanding on February 23, 2012March 3, 2015 was 74,351,533.75,899,415.

DOCUMENTS INCORPORATED BY REFERENCE

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

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W&T OFFSHORE, INC.

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS

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

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PART I

Item 1. Business

W&T Offshore, Inc. is an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties primarily in the Gulf of Mexico and the Permian Basin in West Texas. W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in 1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983.  WeOur interest in fields, leases, structures and equipment are an independent oilprimarily owned by the parent company, W&T Offshore, Inc. and natural gas producer, active in the acquisition, exploration and development of oil and natural gas properties primarily in the Gulf of Mexico and Texas.our wholly-own subsidiary, W & T Energy VI, LLC, a Delaware limited liability company.    

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

During 2011,  Over the last several years, we significantly increasedhave shifted our activityfocus more toward the deepwater and to onshore from what was previously a relatively minor presence. In May 2011, we acquired various properties and leasehold interests in four counties in the Permian Basin of West Texas.  In the deepwater, we have completed numerous acquisitions and drilled both exploration and development wells.  Our deepwater acreage has expanded considerably and currently represents almost half of our offshore acreage on a gross acreage basis.

Our onshore activities have been primarily in the Permian Basin in West Texas, (as described below)where most of our leasehold interests were acquired in a single transaction and separately acquired other leasehold interests2011 acquisition.  During 2014, we reassigned most of our interest in another county in the Permian Basin. In East Texas weacreage acquired in 2011 back to the original assignor and currently have acquiredlimited leasehold interestsinterest in two separate prospect areas. We have been actively exploringEast Texas and developing each of these areas and have had up to eight drilling and workover rigs in service in our onshore operating areas during the year. We anticipate being active in both of these areas of Texas in 2012.Louisiana.  

As of December 31, 2011,2014, we have interests in offshore leases covering approximately 0.81.1 million gross acres (0.5(0.7 million net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama. On a gross acreage basis, the conventional shelf constitutes approximately 52% and deepwater constitutes approximately 48% of our offshore acreage.  Onshore, we have leasehold interests in approximately 0.2 million50,000 gross acres (0.2 million(40,000 net acres), substantially all of which are in Texas. Approximately 82%58% of our total net offshore acreage is developed, and approximately 9%62% of our total net onshore acreage is developed. Of the onshore leasehold classified as undeveloped, almost all can be extended by drilling two additional wells in 2012 and further extended by additional operations or production in future years.

Based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum consultant,consultants, our total proved reserves at December 31, 20112014 were 116.9120.0 million barrels of oil equivalent (“MMBoe”) or 701.1720.0 billion cubic feet of gas equivalent (“Bcfe”). Approximately 46%57% of our reserves were classified as proved developed producing, 19%12% as proved developed non-producing and 35%31% as proved undeveloped. Classified by product, our reserves at December 31, 20112014 were 44%52% oil, 15%13% natural gas liquids (“NGLs”) and 41%35% natural gas. These percentages were determined using the energy-equivalent ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs. This conversionenergy-equivalent ratio does not assume price equivalency, and the energy-equivalent prices for oil, NGLs and natural gas per Mcfe may differ significantly. During 2011, prices for oil were higher than NGLs and natural gas on a million cubic feet equivalent (“Mcfe”) basis, and prices for NGLs were higher than natural gas on a Mcfe basis. Our total proved reserves had an estimated present value of future net revenues discounted at 10% (“PV-10”) of $3.1$2.6 billion. Our PV-10 after considering future cash outflows related to asset retirement obligations (“ARO”) and without deducting future income taxes was $2.8$2.3 billion, and our standardized measure of discounted future cash flows was $2.0$1.7 billion as of December 31, 2011.2014. Neither PV-10 nor PV-10 after ARO is a financial measure defined under generally accepted accounting principles (“GAAP”).  For additional information about our proved reserves and a reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows, seeProperties – Proved ReservesReserveunder Part I, Item 2 ofin this Form 10-K.10-K.

We seek to increase our reserves through acquisitions, exploratory and infill drilling, recompletions and workovers. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to

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add reserves, production and cash flow post-acquisition. Our acquisition team continues to work diligentlystrives to find properties that will fit our profile and that we believe will add strategic and financial value to our company.

As previously mentioned,In September 2014, we acquired additional ownership interest in May 2011, we completedthe Mobile Bay blocks 113 and 132 located offshore Alabama (the “Fairway Field”) and the associated Yellowhammer gas processing plant (collectively “Fairway”), which increased our ownership interest from 64.3% to 100%.  Internal estimates of additional proved reserves associated with the increased ownership interest in the Fairway Field as of the acquisition date were approximately 4.4 MMBoe (26.4 Bcfe), comprised of approximately 24,500 gross acres (21,900 net acres)26% NGLs and 74% natural gas, all of which were classified as proved developed.

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In May 2014, we acquired from Woodside Energy (USA) Inc. (“Woodside”) certain oil and gas leasehold interests in the Permian BasinGulf of West Texas, which we refer to as our “Yellow Rose Properties,” from Opal Resources LLC and Opal Resources Operating Company LLC (collectively, “Opal”Mexico (the “Woodside Properties”).  Based on internalThe Woodside Properties consisted of a 20% non-operated working interest in the producing Neptune field (deepwater Atwater Valley blocks 574, 575 and 618), along with an interest in the Neptune tension-leg platform, associated production facilities and various interests in 24 other deepwater lease blocks. Internal estimates theof proved reserves associated with the Yellow RoseWoodside Properties as of the acquisition date were approximately 30.11.6 MMBoe (180.4(9.4 Bcfe), comprised of approximately 69%89% oil, 22%1% NGLs and 9%10% natural gas, and approximately 70%all of which were classified as proved undeveloped. Including adjustments from an effective date of January 1, 2011, the adjusted purchase price was $394.4 million, and we assumed the ARO associated with the Yellow Rose Properties, which we have estimated to be $0.4 million, and recorded a long-term liability of $2.1 million.developed.

In August 2011,November and December 2013, we completedacquired from Callon Petroleum Operating Company (“Callon”) certain oil and gas leasehold interests in the acquisitionGulf of Shell Offshore Inc.’s (“Shell”Mexico (the “Callon Properties”) 64.3%. The Callon Properties consist of a 15% working interest in the Fairway Field along with a likeMedusa field (deepwater Mississippi Canyon blocks 582 and 583), interest in the associated Yellowhammer gas treatment plant (collectively, the “Fairway Properties”). Based on internalproduction facilities and various interests in other non-operated fields. Internal estimates theof proved reserves associated with the FairwayCallon Properties as of the acquisition dates were approximately 2.1 MMBoe (12.7 Bcfe), comprised of approximately 67% oil and 33% natural gas, all of which were classified as proved developed.

In October 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”), certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”). The Newfield Properties consisted of leases covering 78 federal offshore blocks on approximately 416,000 gross acres (268,000 net acres) predominantly in the deepwater. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were 8.9approximately 7.0 MMBoe (53.5(42.0 Bcfe), comprised of approximately 72%36% oil, 3% NGLs and 61% natural gas, 27% NGLsall of which were classified as proved developed.

From time to time, as part of our business strategy, we sell various properties. In 2014, we had no significant property sales.  In 2013, we sold our non-operated working interests in the Green Canyon 60 field, the Green Canyon 19 field and less than 1% oil and which are 100% proved developed. Including adjustments from an effective date of September 1, 2010, the adjusted purchase price was $42.9 million and we assumedWest Delta area block 29, all located in the ARO associated with the Fairway Properties which we have estimated to be $7.8 million.

During 2010, we closed on two major acquisitions. In April 2010, we acquired two deepwater Gulf of Mexico fields (the “Matterhorn/Virgo Properties”) from Total E&P USA (“Total”) andMexico. In 2012, we sold our non-operated working interest in November 2010, we acquired three deepwaterthe South Timbalier 41 field located in the Gulf of Mexico fields (the “Tahoe/Droshky Properties”) from Shell.Mexico.

Additional information on these acquisitions and divestitures can be found under Properties inProperties under Part I, Item 2,Management’s Discussion and Analysis of Financial Condition and Results of Operationsunder in Part II, Item 7, and inFinancial Statements – and Supplementary Data - Note 2 – Acquisitions and Divestituresunder Part II, Item 8 ofin this Form 10-K.

Our exploration efforts have historically have been in areas in reasonably close proximity to known proved reserves, which we believe reducesbut in 2013, some of our risks.exploration projects were higher risk deepwater projects with potentially higher returns than our previous risk/reward profile. Historically, we have financed our exploratory drilling capital expenditures with netoperating cash provided by operating activities.flow. The investment associated with drilling an offshore well and future development of an offshore project principally depends upon water depth, the depth of the well, the complexity of the geological formations involved and whether the well or project can be connected to existing infrastructure or will require additional investment in infrastructure. Deepwater and deep shelf drilling projects can be substantially more capital intensive than those on the conventional shelf and onshore. Certain risks are inherent in our business specifically and in the oil and natural gas industry and our business,generally, any one of which if it occurs, can negatively impact our rate of return on shareholders’ equity.equity if it occurs. When projects are extremely capital intensive and involve substantial risk, we often seek participants to share the risk. Onshore wells are less capital intensive than offshore wells, but the amount of reserves discovered and developed on a per well basis has historically been less from onshore wells than from offshore wells. During the last three years, we have drilled eight,We completed six, five and 10 successfulfour offshore wells (gross) for the years 2011, 2010 and 2009, respectively33, 40 and drilled 39 successful77 onshore wells (gross) in 2011.

From time to time, as part of our business strategy, we sell various properties that we consider non-core assets. We did not sell any properties in 2011 or 2010. We are currently marketing a package of non-core properties located on the shelf of the Gulf of Mexico.2014, 2013 and 2012, respectively.

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

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Index to Financial Statements

Our totalcurrent capital expenditure budget for 20122015 is $425.0$200 million, not including any potential acquisitions. The budget includes $209.0This compares to capital expenditures of $630 million to drill, evaluate and complete ten offshore wells (six exploration and four development wells) and $170.0 million to drill, evaluate and complete 65 onshore wells (19 exploration and 46 development wells). The budget also includes $46.0$636 million for facilities2014 and 2013, respectively.  The capital recompletions, seismicbudget for 2015 is significantly lower than recent annual expenditures primarily due to the dramatic decline in crude oil prices.  The 2015 budget is being allotted as follows: 38% for exploration, 61% for development and leaseholdless than 1% for other items. Thus far in 2012,Geographically, the budget is split 92% for offshore and 8% for onshore, with the substantial majority of offshore dedicated to the deepwater. Through February 2015, we have not closed on any acquisitions, andbut we continue to evaluate and bid on opportunities as they arise. We anticipate funding our 20122015 capital budget and any potential acquisitions with cash flow from operating activities, cash on hand and borrowings under our revolving bank credit facility and by accessing thefacility. The capital markets towe have historically accessed are currently constrained, but we believe we could access other capital markets if the extent necessary. Our 2012need arises.  Hence, our 2015 capital budget is subjecthas been set with these premises in mind.  For the portion of our capital budget related to change asdrilling, our operating policy has been to fund these expenditures with cash flow provided by operations.  We continue to monitor commodity prices and may revise our capital budget if conditions warrant. We strive to be as flexible as possible and believe this strategy holds the best promise for value creation and growth and managing the volatility inherent in our business. See Risk Factors under Part I, Item 1A in this Form 10-K for additional information.

Business Strategy

We plan to continueOur business strategy is to acquire, explore and develop oil and natural gas reserves on the Outer Continental Shelf (“OCS”), the area of our historical success and technical expertise, which we believe will yieldhas yielded desirable rates of return sufficient to remain competitivecommensurate with our perception of risks. The rapid decline in our industry.oil prices that occurred in the back half of 2014 and continued into the first part of 2015 has created a great deal of uncertainty about future exploration and development. We believe this uncertainty will continue until such time as the costs of goods and services utilized in support of exploration and production become more closely aligned with prevailing commodity prices.  We also believe attractive acquisition opportunities will continue to arisebecome available in the Gulf of Mexico as the major integrated oil companies and other large independent oil and gas exploration and production companies continue to divest properties to focus on larger and more capital-intensive projects that better match their long-term strategic goals. Because of ongoing market volatility, and, more specifically, the significant declinereduction in oil and natural gas prices occurring in the last six months, we also believe thatexpect to find opportunities as other less well-capitalized producers may seek buyers for theirto divest properties both onshore and offshore, which could create opportunities for us.offshore.

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

In addition to pursuing offshore opportunities in the Gulf of Mexico and onshore opportunities in Texas, when market conditions improve, we also plan to continue to pursueevaluate other areas that arecould be compatible with our technical expertise and could yield desirable rates of return sufficient to remain competitive incommensurate with our industry. As described above, we have acquired interests in various onshore properties in Texasperception of risks. We may acquire or expand our offshore and anticipate acquiring or expanding our onshore holdings through acquisitions or exploration, development and development activities.acquisition activities if attractive opportunities arise.

We believe our business approach has contributed to our success and has positioned us to capitalize on new opportunities.  Historically, we have limited our annual capital spending for drilling activities to netoperating cash provided by operating activities,flow, and we have used capacity under our revolving bank credit facility and the capital markets for acquisitions, development and to balance working capital fluctuations.  The capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises.

Competition

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

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Oil and Natural Gas Marketing and Delivery Commitments

We sell our oil, NGLs and natural gas to third-party purchasers.customers. We are not dependent upon, or contractually limited to, any one purchasercustomer or small group of purchasers.customers. However, in 2011 we sold over2014, approximately 47% of our sales were to Shell Trading (US) Co. and no other customer comprised greater than 10% of our production to each of Shell Trading (US) Co., Conoco Phillipssales.  See Financial Statements  and JP Morgan Ventures Energy Corp. and these three companies accounted for approximately 62% of our total sales. SeeFinancial StatementsSupplementary Data – Note 1 – Significant Accounting Policies – Concentration of Credit Risk in under Part II, Item 8 ofin this Form 10-K 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 with numerous purchasers in the Gulf of Mexico and Texas, we do not believe the loss of a single purchasercustomer or a few purchaserscustomers would materially affect our ability to sell our production. We do not have any agreements thatwhich obligate us to deliver certainmaterial quantities to third parties.

Regulation

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

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

Regulation and transportation of natural gas.Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The rates for such storage and transportation services are subject to FERC ratemaking authority, and FERC exercises its authority either by applying cost-of-service principles or granting market based rates.

Similarly, the natural gas pipeline industry may also be subject to state regulations which may change from time to time. During the 2007 legislative session, the Texas State Legislature passed H.B. 3273 (“Competition Bill”) and H.B. 1920 (“LUG Bill”). The Competition Bill gives the Railroad Commission of Texas (“RRC”) the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the

requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and

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gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale, transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. The RRC was subject to a sunset conditionreview during 2013 and proposalswas authorized to operate for certain changes were made, but no legislation was enacted during 2011 and the RRC will be reviewed againan additional four years.  Its next scheduled sunset review is in 2013.2017.

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The Outer Continental Shelf Lands Act (“OCSLA”), which is administered by the Bureau of Ocean Energy Management⁽¹⁾ (“BOEM”) and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers working in the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. On June 18, 2008, the BOEM issued a final rule, effective August 18, 2008, that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.

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

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

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

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

Index to Financial Statements

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

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

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

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

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To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees have substantial net worthdemonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied.  The significant reductions in oil and natural gas pricing since the middle of 2014 may also adversely impact the BOEM’s financial assurance determinations with respect to the Company. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases.  W&T Offshore, Inc. is currently exempt from supplemental bondingIn August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements byfor companies operating in federal waters. If the BOEM. As many BOEM regulations are being reviewed, we may be subjectwere to supplemental bondingincrease its financial assurance requirements in the future.substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated.  Any such suspension or termination could materially adversely affect our financial condition and results of operations.  SeeRisk Factors – BP’s Deepwater Horizon explosionIn addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and ensuing oil spill couldabandonment liabilities. According to federal regulations, the BOEM will waive its supplemental bonding requirements when a lessee or its guarantor can demonstrate the financial capability and reliability to meet these obligations.  We have broad adverse consequences affectingdemonstrated our financial capability and reliability to the satisfaction of the BOEM and the agency does not require that the Parent Company post any supplemental bonds to cover our operations on the OCS.

In December 2013 and January 2014, we were notified by the Office of Natural Resources Revenue (“ONRR”) of an underpayment of royalties on certain Federal offshore oil and gas leases that cumulatively approximated $30,000 over several years, which represents 0.0045% of royalty payments paid by us during the same period of the underpayment.  In March 2014, we received notice from the ONRR of a statutory fine of $2.3 million relative to such underpayment.  We believe the fine is excessive and extreme considering the circumstances and in relation to the amount of underpayment.  On April 23, 2014, we filed a request for a hearing on the record and a general denial of the ONRR’s allegations contained in the Gulf of Mexico, some of whichnotice.  We intend to contest the fine to the fullest extent possible. The ultimate resolution may be unforeseeableunder Part I, Item 1Aresult in this Form 10-Kfor more information.

The ONRR administers the collection of royalties under the termsa waiver of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the termsfine, a reduction of the oil and natural gas leasesfine, or payment of the full amount plus interest covering several years.  As no amount has been determined as wellmore likely than any other within the range of possible resolutions, no amount has been accrued as of December 31, 2014 per authoritative guidance.  However, we cannot state with certainty that our estimate of the regulations promulgated by the ONRR and the BOEM.exposure is accurate concerning this matter.

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

Environmental Regulations

Index to Financial Statements

General. Environmental regulations.We are subject to complex and stringent federal, state and local environmental laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and producing operations, the amounts and types of materials that may be released into the environment, the discharge and disposal of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent and address pollution, such as the closure of inactive oil and gas waste pits and the plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. The remediation, reclamation and abandonment of wells, platforms and other facilities in the Gulf of Mexico aremay require us to incur significant costs to us.costs. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.

We are currently under investigation by the United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the U.S. Environmental Protection Agency (the “EPA”) for alleged violation of environmental laws6

Hazardous Substances and regulations at certain of our operational sites. The outcome of this investigation could have a material adverse effect upon us. We are not able at this time to estimate our potential exposure, if any, related to this matter. See Legal Proceedings under Part I, Item 3 in this Form 10-K for additional information. At our other operation sites, we believe we are in substantial compliance with current applicable environmental laws and regulations. We believe that compliance with existing requirements will not have a material adverse impact on our operations, but failure to comply could have material consequences. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.

Wastes.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.  Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.  In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

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

Index to Financial Statements

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.  Additionally, Naturally Occurring Radioactive Materials (“NORM”) may contaminate minerals extraction and processing equipment used in the oil and natural gas industry.  The waste resulting from such contamination is regulated by federal and state laws.  Standards have been developed for: worker protection; treatment, storage, and disposal of NORM and NORM waste; management of NORM-contaminated waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws.  We do not anticipate any material expenditures in connection with our compliance with RCRA and applicable state laws related to NORM waste.

Air Emissions.  Air emissions from our operations are subject to the Federal Clean Air Act (“CAA”) and comparable state and local requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. On July 28, 2011,For example, the EPA proposed rules that would establish newU.S. Environmental Protection Agency (“EPA”) has established air emission controls requirements for oil and natural gas production and natural gas processing operations.  Specifically, the EPA’s proposed rule package includesEPA established New Source Performance Standards to addressfor emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to addressfor hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal wouldEPA rules require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquidsany hydrocarbons that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. EPA is currently considering comments submitted on the proposedThese rules and has indicated that it expects to adopt final rules by April 3, 2012. If finalized, these rules couldmay require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

In December 2009, theClimate Change. The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recentlyhas adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases fromrequires preconstruction and operating permits for certain large stationary sources, effective January 2, 2011.sources. The EPA has also adopted rules requiringrequires the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis effective in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginningbasis. We believe we are in 2012 for emissions occurring in 2011. We expect to be able to complycompliance with this emissionsnew emission reporting requirement foras it applies to our onshore operations in West Texas.operations.  

The7

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

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

Index to Financial Statements

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Water Discharges.  The primary federal law for oil spill liability is the Oil Pollution Act (the “OPA”) which amends and augments oil spill provisions of the Cleanfederal Water Act.Pollution Control Act (the “Clean Water Act”). OPA imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters, including the OCS or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several, strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil and natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In addition, in December 2014, the BOEM issued a final rule, effective January 12, 2015, which raises OPA’s damages liability cap from $75 million to $133.65 million. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to a maximum of $150 million. We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS. As a result of the BP Deepwater Horizon incident, legislation has been proposed in Congress to increase the minimum level of financial responsibility to $300 million or more. If OPA is amended to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if there was an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the monitoring and discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state.  The EPA has also adopted regulations requiring certain onshore oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.  Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our onshore facilities.  Obtaining permits has the potential to delay the development of oil and natural gas projects.  These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs.  Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil.  We currently maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms.

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Hydraulic Fracturing.Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand or other proppants and chemicals under pressure into the formation to fracture the surrounding rock formation and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”(the “SDWA”) over certain hydraulic fracturing activities involving the use of diesel.diesel fuel and issued permitting guidance covering such activities in February 2014. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Effective February 1, 2012,For example, in May 2013, the RRC began requiring all operators to disclose on a public website the chemical ingredientsadopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water volumes used to hydraulically fracture wells in Texas.resources.  We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities.activities including disclosure requirements. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells that require hydraulic fracturing.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has

Index to Financial Statements

commencedis performing a study of the potential environmental effects of hydraulic fracturing on drinking water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and groundwater, with initial results expectedproduced water, and wastewater treatment and disposal. The EPA has indicated that it expects to be available by late 2012 and final results by 2014. Moreover, theissue its study report in 2015. The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014.in 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

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

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

Certain flora and fauna that have been officially 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 could be required. The U.S. Fish and Wildlife Service is currently considering whether the dunes sagebrush lizard, which is present in certain areas of the Permian Basin near the Texas-New Mexico border, should be listed as endangered. It is possible that

We own a decision to list the dunes sagebrush lizard as endangered could have an adverse impact on our operations in West Texas.

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

Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act, the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Magnuson-Stevens Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands. These and other protected areas may require certain mitigation measures to avoid harm to wildlife, and such laws and regulations may impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. Naturally Occurring Radioactive Materials (“NORM”) may

Index to Financial Statements

contaminate minerals extraction and processing equipment used in the oil and natural gas industry. The waste resulting from such contamination is regulated by federal and state laws. Standards have been developed for worker protection; treatment, storage and disposal of NORM and NORM waste; management of waste piles, containers and tanks; and limitations on the relinquishment of NORM contaminated land for unrestricted use under RCRA and state laws. We do not anticipate any material expenditures in connection with our compliance with RCRA and applicable state laws related to NORM waste.9

We maintain liability insurance and well control insurance for all of our operations. In addition, we maintain property and hurricane damage insurance coverage for some, but not all, of our properties, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain does not cover the risks described above from gradual pollution events which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover such risks or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant environmental event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claims and Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on insurance coverage.

Seasonality

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

Employees

As of December 31, 2011,2014, we employed 310339 people. We are not a party to any collective bargaining agreements and we have not experienced any strikes or work stoppages. We consider our relations with our employees to be good.

Additional Information

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

Item 1A. Risk Factors

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our industryus and our Companyindustry could materially impact our future performance and results of operations. We have provided below a list of known material risk factors that should be reviewed when considering buying or selling 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.

Index to Financial Statements

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

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

The price we receive for our oil, NGLs and natural gas production directly affects our revenues, profitability, access to capital and future rate of growth. Oil, NGLs and natural gas are commodities and are subject to wide price fluctuations in response to relatively minor changes in supply and demand. Lower prices for our oil, NGLs and natural gas production may not only decrease our revenues on a per unit basis but may also reduce the amount of oil, NGLs and natural gas that we can produce economically. Historically, the markets for oil, NGLs and natural gas have been volatile and will likely continue to be volatile in the future. The prices we receive for our production and the volume of our production depend on numerous factors beyond our control. These factors include the following:

10

The prices of crude oil, domestic natural gas and liquefied natural gas;

Lower oil and natural gas prices may not only decrease our revenuesproducers to varying degrees depending on a per unit basis but may also reduce the amount of oil and natural gas that we can produce economically. For example, the prices of oil and natural gas declined substantially during the second half of 2008 and impacted production volumes.hedging strategies.  Natural gas and NGLs prices have been negatively affected by the domestic economy, excess natural gas production, high levels of stored natural gas and weather conditions affecting demand. In recent months, Henry Hub spot prices for natural gas have declined to prices lower than $3.00 per Mcf compared to average prices during 2014 in excess of $4.00 per Mcf. There have been significant recent development activities in shale and other resource plays, which have the potential to yield a significant amount of natural gas and NGLs production, as well as natural gas and NGLs produced in connection with increased domestic oil drilling activities. The potential increases in natural gas supplies resulting from the large-scale development of these unconventional resource reserves could continue to have an adverse impact on the price of natural gas.gas and NGLs. An environment of depressedfurther or continued lower oil, NGLs and natural gas prices would materially and adversely affect our future business, financial condition, results of operations, liquidity and/or ability to finance planned capital expenditures.

If oil, NGLs and natural gas prices stay at their current levels or decrease further, we maywill likely 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 maywill likely be required to write down the carrying value of our oil and natural gas properties. A write-down constitutesSuch write-downs constitute a non-cash charge to earnings.  Primarily as a resultImpairment of proved properties under our full cost oil and gas accounting method is largely driven by the present values of future net revenues of proved reserves estimated using SEC mandated 12-month unweighted first-day-of-the-month commodity prices. Since oil, gas and NGLs prices did not decline in 2014 until after June 2014, and more prominently in the fourth quarter of 2014, the impact of the significant declinerecent pricing downturns will continue to adversely affect our SEC average pricing as recent and current prices roll into the SEC average prices used in bothevaluating impairment of our proved reserves under the full cost accounting “ceiling test”.   While we have not had any ceiling test impairments since 2009, sustained current prices or further declines in prices for oil, NGLs and natural gas will likely result in future ceiling test impairments.  You should not assume that the $2.6 billion present value of future net revenues, PV-10, from our proved oil and natural gas prices asreserves shown elsewhere in this document is the current market value of December 31, 2008, we recorded a ceiling test impairment at December 31, 2008 of $1.2 billion. Additionally, we recorded a ceiling test impairment at March 31, 2009 of $218.9 million primarily

Index to Financial Statements

as a result of a further decline in natural gas prices as of March 31, 2009. We did not have any impairment write-downs in 2011 or 2010. Declines inour estimated oil and natural gas reserves.  (PV-10 is not a financial measure defined under GAAP.  For additional information about our proved reserves and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, see Properties – Proved Reserve under Part I, Item 2 in this Form 10-K.)  In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate.  Actual future prices afterand costs may differ materially from those used in the present value estimate.  For example, the average price used in the standardized measure of discounted cash flows for December 31, 2011 may require us to record additional ceiling test impairments2014 for crude oil was $91.12 per barrel and the average price of WTI crude oil in the future.December 2014 was $59.29 per barrel.   No assurance can be given that we will not experience a ceiling test impairmentimpairments in future periods, which could have a material adverse effect on our results of operations in the periodperiods taken. As a result of lower oil, NGLs and natural gas prices, we may also reduce our estimates of the reservesreserve volumes that may be economically recovered, which would reduce the total value of our proved reserves. SeeManagement’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Impairment of oil and natural gas propertiesin under Part II, Item 7 andFinancial Statements and Supplementary Data – Note 1 – Significant Accounting Policiesinunder Part II, Item 8 ofin this Form 10-K for additional information on the ceiling test.

The Company is responding to a federal grand jury investigation that could result in penalties and additional operating restrictions.

The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the EPA, is conducting a federal grand jury investigation of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms in the Gulf of Mexico. We are fully cooperating with the investigation. The United States Attorney’s Office has recently informed us that they are continuing their investigation with the intent to seek a criminal disposition. The outcome of this investigation could have a material adverse effect upon us. We are not able at this time to estimate our potential exposure, if any, related to this matter.

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

On May 6, 2009, certain Cameron Parish land owners filed suit in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and Tracy W. Krohn as well as several other defendants unrelated to us. In their lawsuit, plaintiffs are alleging that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and are seeking compensatory and punitive damages. We cannot currently estimate our potential exposure, if any, related to this lawsuit. We are currently, and intend to continue, vigorously defending this litigation.

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

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

In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEM and BSEE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico more difficult, more time consuming, and more costly. For example, a variety of amendments to the OPA have been

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proposed in response to the Deepwater Horizon incident. OPA and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the OCS, which includes the Gulf of Mexico where we have substantial offshore operations. OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. OPA also requires operators to provide evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. We are currently required to demonstrate, on an annual basis, that we have ready access to $150 million that can be used to respond to an oil spill from our facilities on the OCS. Legislation has been proposed in Congress to amend OPA to increase the minimum level of financial responsibility to $300 million or more. If the minimum level of financial responsibility is increased further, we may experience difficulty in providing financial assurances sufficient to comply with the revised requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased further.

After the moratorium ended in 2010, it was not until March 2011 that deep water drilling permits began to be issued, and even then only sporadically, to continue drilling activities that had commenced prior to the Deepwater Horizon incident. Since March 2011, deepwater drilling permits have been issued at a slower and more measured pace than before the Deepwater Horizon event.

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

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

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

As a result of the issuance of these new NTLs and the lack of detail therein, the BOEM has been taking much longer to review and approve permits for new wells. Due to the extremely slow pace of permit review and

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approval, various industry sources have determined that the BOEM may take six months or longer to approve applications for drilling permits that were previously approved in less than 30 days. These NTLs also increase the cost of preparing each permit application and will increase the cost of each new well, particularly for wells drilled in deeper waters on the OCS. The delay in granting permits could also cause some of our leases to lapse as a result of failure to commence drilling or continue production operations.

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

In addition to the NTLs discussed previously, the BOEM issued NTL No. 2010-G05 dated effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” – wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease – in the Gulf of Mexico. This NTL sets forth more stringent standards for decommissioning timing requirements by requiring that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations.The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future ARO required to meet such increased costs. For the year 2010, we increased our estimate of ARO by $18.7 million based on our expected acceleration in timing for such obligations as a result of implementing this NTL. (For additional details, refer toFinancial Statements – Note 5 – Asset Retirement Obligationsin Part II, Item 8 of this Form 10-K.) The potential increase in decommissioning activity in the Gulf of Mexico over the next few years as a result of the NTL may result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related ARO.

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

On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA is currently considering comments submitted on the proposed rules and has indicated that it expects to adopt final rules by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our operating results.

We were adversely affected by a recession in the United States and global economy.

The United States and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. The recession that began in 2008 caused a collapse in oil and natural gas prices resulting in write-downs of the value of our reserves at the end of 2008 and early 2009. These write-downs significantly reduced our stockholders’ equity, increased our financial leverage, reduced the market value of our common

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stock and reduced the market value of our long-term debt. There are likely to be long-term effects resulting from the recession, the credit market crisis and the recent issues concerning the Euro and the debt of certain European countries. These and other factors may cause future economic growth rate to be slower than what was experienced before the recession began. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. A lower future economic growth rate could result in decreased demand growth for our oil and natural gas production as well as lower commodity prices, which could reduce our cash flows from operations and our profitability.

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

As of December 31, 2011, available borrowings under our revolving bank credit facility are currently limited to $575.0 million, less outstanding borrowings and letters of credit. Availability is determined semi-annually by our lenders and is based in part on oil and natural gas prices and in part on our proved reserves. Substantially all of our oil and natural gas properties are pledged as collateral under the credit agreement governing our revolving bank credit facility (the “Credit Agreement”). The Credit Agreement limits our ability to incur additional indebtedness based on specified financial covenants, ratios or other criteria. Lower oil and natural gas prices in the future could result in a reduction in credit availability and also affect our ability to satisfy these covenants, ratios or other criteria and thus could reduce our ability to incur additional indebtedness and our ability to replace reserves.

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

We could be exposed to uninsured losses in the future. The occurrence of a significant accident or other event not covered in whole or in part by our insurance could have a material adverse impact on our financial condition and operations. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. In May and June 2011, we renewed our insurance policies covering well control and hurricane damage at an annual cost of approximately $30.7 million. The amount of properties covered and dollar coverage was increased from 2010, but the retention amount per hurricane occurrence was also increased, which increases our risk. In addition, pollution and environmental risks are generally not fully insurable. Because third-party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented.

SeeFinancial Statements – Note 3 – Hurricane Remediation and Insurance Claimsunder Part II, Item 8 of this Form 10-K for additional information.

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

Due to insurance claims in recent years associated with hurricanes in the Gulf of Mexico and global catastrophic losses, property damage and well control insurance coverage has become more limited and the cost of such coverage has become both more costly and more volatile. The insurance market may change dramatically in the future due to the major oil spill that occurred in 2010 at BP’s Macondo well in the deepwater Gulf of Mexico. As of December 31, 2011, approximately 93% of our PV-10 value of proved reserves attributable to our Gulf of Mexico properties are on platforms that are covered under our current insurance policies for named windstorm damage. Our insurers may not continue to offer this type and level of coverage to us, our costs may increase substantially as a result of increased premiums and the losses that may have been previously insured may no longer be insured. The occurrence of any or all of these possibilities could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have a claim, the insurance companies will not pay our claim.

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Commodity derivative positions may limit our potential gains.

In order to manage our exposure to price risk in the marketing of our oil and natural gas, we may periodically enter into oil and natural gas price commodity derivative positions with respect to a portion of our expected production. We do not enter into derivative instruments for speculative trading purposes. While these commodity derivative positions are intended to reduce the effects of volatile oil and natural gas prices, they may also limit future income if oil and natural gas prices were to rise substantially over the price established by such positions. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

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

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

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

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As of December 31, 2011,2014, approximately 35%31% of our total proved reserves were undeveloped and approximately 19%12% 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.

Our undeveloped proved reserves and developed non-producing proved reserves require additional expenditures and/or activities to convert these into producing reserves.  We cannot provide assurance these expenditures will be made and that activities will be entirely successful in converting these reserves.  Additionally, we are not the operator with respect tofor approximately 10%17% of our undeveloped proved reserves and approximately 11% of our proved developed non-producing reserves, so we may not be in a position to control the timing of all development activities.  Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.

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

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

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

Unless we conduct successful development and exploration activities at sufficient levels or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced.  Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending upon

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reservoir characteristics and other factors.  High production rates generally result in recovery of a relatively higher percentage of reserves during the initial few years of production.  The majority of our current production is from the Gulf of Mexico.  Production from reservoirsReserves in the Gulf of Mexico generally decline more rapidly than from reservoirsreserves in many other producing regions of the United States.  Our independent petroleum consultant estimates that on average, 43%42% of our total proved reserves arewill be depleted within three years.  As a result, our need to replace reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their reserves over a similar time period, such as those producers who have a larger portion of their reserves in areas other than the Gulf of Mexico.  We may not be able to develop, find or acquire additional reserves in sufficient quantities to sustain our current production levels or to grow production beyond current levels.  In addition, due to the significant time requirements involved with exploration and development activities, particularly for wells in the deepwater or wells not located near existing infrastructure, actual oil and natural gas production from new wells may not occur, if at all, for a considerable period of time following the commencement of any particular project.

Significant capital expenditures are required to replace our reserves.  If we are not able to replace reserves, we will not be able to sustain production at current levels.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable.  Unless we replace the reserves we produce through successful exploration, development or acquisition activities, our proved reserves and production will decline over time.  Our exploration, development and acquisition activities require substantial capital expenditures.  Historically, we have funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, securities offerings and bank borrowings.  In orderThe capital markets we have historically accessed are currently constrained, but we believe we could access other capital markets if the need arises. These limitations in the capital markets may affect our ability to finance future capital expenditures, we may need to alter or increasegrow and changes in our capitalization substantially through the issuance of additional debt or equity securities, bank borrowings, reserve-based loans, joint ventures or other means. These changes in capitalizationstructure may significantly affect our financial risk profile.  Furthermore, we cannot be certain that financing for future capital expenditures will be available if needed, and to the extent required, on acceptable terms. For additional financing risks, see “– Risks Related to Financings.”

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

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

As of December 31, 2014, borrowing availability under our revolving bank credit facility was $750 million, less outstanding borrowings of $447 million and letters of credit of less than $1 million, resulting in net availability of $302 million.  Availability is determined semi-annually by our lenders and is based on oil, NGLs and natural gas prices and on our proved reserves.  Substantially all of our oil and natural gas properties are pledged as collateral under the Fifth Amended and Restated Credit Agreement (the “Credit Agreement”) governing our revolving bank credit facility.  The Credit Agreement limits our ability to incur additional indebtedness based on specified financial covenants, ratios or other criteria.  Sustained and/or lower oil, NGLs and natural gas prices in the future could result in a reduction in credit availability and also affect our ability to satisfy these covenants, ratios or other criteria and thus could reduce our ability to incur additional indebtedness and our ability to replace reserves.

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The Company could face additional requirements if it does not comply with the terms of its probation.

On January 3, 2013, the Company (i) pled guilty to one felony count under the Clean Water Act for altering monthly produced water discharge samples for the Ewing Banks 910 platform in 2009 and one misdemeanor count under the Clean Water Act for failure to report the discharge of a small amount of oil from the same platform in November 2009, (ii) paid a $0.7 million fine and $0.3 million for community service and (iii) entered into an environmental compliance program subject to a third-party audit. Under the agreement, the Company was placed on a three-year term of probation, which ends on January 3, 2016. The probation terms require that the Company commit no further environmental law violations, comply with an Environmental Compliance Plan during the probation period and take no adverse action against personnel who cooperated in the investigation. The agreement further stipulates that the Government will not seek any further criminal charges against the Company in this matter. Failure to comply with the terms of the agreement could lead to additional requirements and/or operating restrictions.

More stringent regulatory initiatives relating to offshore exploration and production activities may have an adverse effect on our results of operations, financial position and liquidity.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals, and substantial rules adopted, by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. The federal government, acting through the U.S. Department of the Interior and its implementing agencies that have since evolved into the present day BOEM and BSEE, has issued various rules, NTLs and temporary drilling moratoria.  These rules and requirements impose or result in added environmental and safety measures upon exploration, development and production operators in the Gulf of Mexico including the following:

These new regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits.  These new requirements also increase the cost of preparing permit applications and increase the cost of each new well, particularly for wells drilled in the deepwater on the OCS.  We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements.  Moreover, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere where we conduct operations, the relevant governmental authorities could elect to again issue directives to temporarily cease drilling activities.  In any event, they may from time to time issue further safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our production activities as well as our financial position, results of operations and liquidity.

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Requirements imposed by the BOEM and BSEE related to the decommissioning, plugging, and abandonment of offshore facilities could significantly impact the cost of operating our business.

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

To cover the various obligations of lessees on the OCS, the BOEM generally requires that lessees demonstrate financial strength and reliability according to regulations or post bonds or other acceptable assurances that such obligations will be satisfied.  In addition, in August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements for companies operating in federal waters.  If BOEM were to increase its financial assurance requirements substantially, such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. The significant reductions in oil and natural gas pricing since the middle of 2014 may also adversely impact the BOEM’s financial assurance determinations with respect to the Company. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated.  Any such suspension or termination could materially adversely affect our financial condition and results of operations. In addition, the BOEM can require supplemental bonding from operators for decommissioning, plugging, and abandonment liabilities if financial strength and reliability criteria are not met.  

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

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

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

We could be exposed to uninsured losses in the future. The occurrence of a significant accident or other event not covered in whole or in part by our insurance could have a material adverse impact on our financial condition and operations. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. In May and June 2014, we renewed our insurance policies covering well control, hurricane damage, general liability and pollution.  These policies reduce, but do not totally mitigate, our risk as we are exposed to amounts for retention and co-insurance, limits on coverage and some events that are not insured. These policies expire in May and June 2015.  We also have other smaller per-occurrence retention amounts for various other events.  In addition, pollution and environmental risks are generally not fully insurable, as gradual seepage and pollution are not covered under our policies. Because third-party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claims and Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on insurance coverage.

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

Due to insurance claims in recent years associated with hurricanes in the Gulf of Mexico and global catastrophic losses, property damage and well control insurance coverage has become more limited and the cost of such coverage has become both more costly and more volatile. The insurance market may change dramatically in the future due to the major oil spill that occurred in 2010 at BP’s Macondo well in the deepwater Gulf of Mexico. As of December 31, 2014, virtually all of our PV-10 value of proved reserves attributable to our Gulf of Mexico properties is on platforms that are covered under our current insurance policies for named windstorm damage. Our insurers may not continue to offer us the type and level of our current coverage, or our costs may increase substantially as a result of increased premiums and there could be an increased risk of uninsured losses that may have been previously insured. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurance companies will not pay our claims. The occurrence of any or all of these possibilities could have a material adverse effect on our financial condition and results of operations.

Commodity derivative positions may limit our potential gains.

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

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

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

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil, NGLs and natural gas and securing trained personnel. Many of our competitors have financial resources that allow them to obtain substantially greater technical expertise and personnel than we have. We actively compete with other companies in our industry when acquiring new leases or oil and natural gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. On the acquisition opportunities made available to us, we compete with other companies in our industry for such properties through a private bidding process, direct negotiations or some combination thereof. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted. The availability of properties for acquisition depends largely on the divesting practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors we cannot control or influence.