Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion 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 Exchange Act of 1934, which involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. 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 our Annual Report on Form 10-K for the year ended December 31, 2011 and may be discussed or updated from time to time in subsequent reports filed with the 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. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to "W&T," "we," "us," "our" and the "Company" refer to W&T Offshore, Inc. and its consolidated subsidiaries.

Overview

We are an independent oil and natural gas producer focused primarily in the Gulf of Mexico and Texas. We have grown through acquisitions, exploration and development and currently hold working interests in 67 producing offshore fields in federal and state waters, and in the deepwater. During 2011, we expanded onshore into West Texas and East Texas where we are actively pursuing exploration and development activities. However, the majority of our daily production continues to be derived from wells we operate offshore. In managing our business, we are concerned primarily with maximizing long-term return on shareholders' equity. To accomplish this primary goal, we focus on profitably increasing production and finding oil and gas reserves at a favorable cost. We strive to increase our reserves and production through acquisitions and our drilling programs. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, natural gas liquids ("NGLs") and natural gas production and the prices that we receive for such production. For the nine months ended September 30, 2012, our combined total production of oil, condensate, NGLs and natural gas increased by 2.3% and our combined average realized sales prices decreased by 12.3% compared to the same period in 2011 based on an energy equivalency ratio. Our production volumes for the nine months ended September 30, 2012 were comprised of approximately 34.6% oil and condensate, 12.5% NGLs and 52.9% natural gas. In the nine months ended September 30, 2012, oil sales represented 72.5% of total revenues, while NGLs represented 10.2% and natural gas represented 17.1% of total revenues. Energy equivalency is determined using the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of crude oil, condensate or NGLs and is reported herein as thousand cubic feet equivalent ("Mcfe") or barrel of equivalent ("Boe"). The conversion ratio does not assume price equivalency, and the price per Mcfe for oil, NGLs and natural gas may differ significantly.

On October 5, 2012, we completed the acquisition of certain oil and gas leasehold interests from Newfield. The stated purchase price was $228.0 million, subject to certain adjustments, including adjustments from an effective date of July 1, 2012 until the closing date, October 5, 2012. The preliminary adjusted purchase price, excluding ARO was $207.7 million, which is subject to further post-effective date adjustments and the assumption of future ARO estimated at $30.4 million for these properties. The properties acquired consist of leases covering 78 federal offshore blocks on approximately 432,700 gross acres (416,000 gross acres excluding over-riding interests), comprised of 65 blocks in the deepwater, six of which are producing, ten blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. The Newfield Properties had estimated proved reserves as of July 1, 2012 of 7.7 million barrels of oil equivalent ("MMBoe") or 46.0 billion cubic feet equivalent ("Bcfe") comprised of approximately 60% natural gas, 36% oil and 4% NGLs and 100% of which were classified as proved developed. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand.

During 2011, we closed two acquisition transactions. On May 11, 2011, we completed the acquisition of the Yellow Rose Properties, which consisted of approximately 24,500 gross acres (21,900 net acres) of oil and gas leasehold interests in the Permian Basin of West Texas. Based on internal estimates, proved reserves associated with the Yellow Rose Properties as of the acquisition date were approximately 30.1 MMBoe, or 180.4 Bcfe, comprised of approximately 69% oil, 22% NGLs and 9% natural gas, and approximately 30% of which were classified as proved developed. The adjusted purchase price was $394.4 million excluding ARO and long-term liabilities. We assumed the ARO, which we estimated to be $0.4 million, and recorded a long-term liability of $2.1 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

On August 10, 2011, we completed the acquisition of the Fairway Properties, which consisted of a 64.3% working interest in the Fairway field along with a like interest in the associated Yellowhammer gas treatment plant. Based on internal estimates, proved reserves associated with the Fairway field as of the acquisition date were 8.9 MMBoe (53.5 Bcfe) comprised of approximately 72% natural gas, 27% NGLs and less than 1% oil and 100% of which were classified as proved developed. As of September 30, 2012, the adjusted purchase price was $40.2 million excluding ARO. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the fourth quarter of 2012. We assumed the ARO associated with the properties and plant, which we estimated to be $7.8 million. The acquisition was funded from borrowings under our revolving bank credit facility.

Industry Trends

During the nine months ended September 30, 2012, our average realized oil sales price (unhedged) increased 2.0% compared to the nine months ended September 30, 2011. Two comparable benchmarks are the unweighted average daily posted spot price of WTI crude oil and the unweighted average daily posted spot price of Brent crude oil, which increased 1.0 % and 0.2 %, respectively from the comparable 2011 period. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price plus a premium depending on the type of crude oil. Most of our oil production is from our offshore operations and is comprised of various crudes including Heavy Louisiana Sweet, Light Louisiana Sweet, Poseidon and others. Starting in the first quarter of 2011 and continuing through the nine months ended September 30, 2012, these various crudes sold at a significant premium relative to WTI. During the nine months ended September 30, 2012, premiums for Heavy Louisiana Sweet crude ranged between $11.00 and $22.00 per barrel and premiums for Light Louisiana Sweet crude ranged between $10.00 and $21.00 per barrel. For the month of September 2012, the average premium for these crudes was between $17.00 and $18.00 per barrel. In comparison, the average premium for these crudes was between $4.00 and $24.00 per barrel for the nine months ended September 30, 2011, and in 2010, the average premium was approximately $2.00 to $3.00 per barrel, which is representative of the historical norm. We may continue to experience higher premiums to WTI crude in our future sales of crude oil until such time as the causative factors, described below, are resolved. We cannot predict with any certainty how long such pricing conditions will last.

A possible cause cited by industry publications for the premiums afforded our offshore crudes is an over supply situation at Cushing, Oklahoma, a primary domestic hub for crude oil priced using the WTI benchmark. Citing the Cushing crude over supply situation, the owners of the Seaway pipeline reversed the flow of crude oil in June 2012 to flow crude from Cushing to Freeport, Texas. The pipeline has a current capacity of 150,000 barrels per day. The owners have also announced plans to increase the capacity to 400,000 barrels per day in early 2013 and to construct a parallel pipeline to be completed in mid-2014, which is expected to double the capacity to 850,000 barrels per day. We believe these plans should help relieve most of the over supply situation at Cushing, which may affect the premiums we receive on our offshore oil production although we did not experience a decline in the third quarter of 2012. An additional factor that has appeared to affect the premiums for Heavy Louisiana Sweet and Light Louisiana Sweet is the difference between the Brent and WTI crude oil prices, which continue to have a higher spread than historical norms. When the price of Brent crude increases relative to WTI, the value of low-sulfur U.S. crude grades that compete with West African crude increases. This trend of higher Brent spreads began in the first quarter of 2011 and has continued through the nine months ended September 30, 2012.

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

Not withstanding this long-term view, crude oil prices may continue to be volatile. For the nine months ended September 30, 2012, WTI crude oil prices have ranged from a high of approximately $109.00 per barrel to a low of $78.00 per barrel. The volatility in price was attributed by some commentators to be due in part to the debt crisis in Europe and the

belief that economic growth in certain world markets was weakening. The U.S. Energy Information Administration ("EIA") expects the oil market to loosen in the near term as consumption falls from its seasonal peak and output outside of OPEC recovers from unplanned outages. EIA expects consumption growth to come primarily from China, the Middle East, Central and South America. EIA estimates global oil demand for 2012 and 2013 at 89.1 and 90.0 million barrels per day, respectively, which would be less than 1% growth for each year.

Our average realized NGLs sales prices (unhedged) decreased 26.1% during the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011. According to industry sources, domestic NGLs production significantly increased over 2011 levels which affected price realizations. During the nine months ended September 30, 2012, prices for domestic ethane and propane, two common NGL components, decreased 44% and 29%, respectively, from the nine months ended September 30, 2011 and other domestic NGLs prices decreased 9% to 10%. As long as ethane and propane inventories continue to be high and NGLs production continues to increase, we could expect prices for these two commodities to be weak. In addition, as long as the crude to natural gas price ratio remains wide, NGLs production may continue to be high, which may put downward pressure on the entire NGLs stream.

Natural gas prices are much more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues and domestic economic conditions, and they have historically been subject to substantial fluctuation. During the nine months ended September 30, 2012, our average realized sales price of natural gas (unhedged) decreased 37.3% from the nine months ended September 30, 2011 to $2.72 per Mcf. A comparable bench mark is the Henry Hub unweighted average daily posted spot price, which decreased 39.8% from the comparable period. We expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas storage levels continuing to build to ever higher levels throughout this injection season, (iii) natural gas continuing to be produced as a by-product in conjunction with the substantial ramp up of oil drilling, (iv) increasing availability of liquefied natural gas and (v) production efficiency gains are achieved in the shale gas areas resulting from better fracking, horizontal drilling and production techniques. EIA estimates that natural gas consumption in 2012 will increase 4.7% from 2011 to 69.8 billion cubic feet per day due to gains in electrical power use offsetting declines in residential, commercial and industrial consumption and expects 2013 consumption to be approximately equal to 2012 levels. The EIA expects production growth to decrease in 2013 due to the decrease in current domestic natural gas rig count of approximately 50% as compared to the natural gas rig count from 2012. Due to the high production and historically high inventory levels, we believe natural gas prices may continue to be weak until such time as crude prices weaken (which will in turn decrease oil drilling activity and decrease the likelihood of producing natural gas as a by product), economic activity increases dramatically or fuel switching increases.

Over the last several months, the United States has experienced fuel switching between coal and natural gas in the production of electricity. However, the EIA indicates that higher expected natural gas prices will reduce the percentage of electrical power generation from natural gas from a projected 27.8% in the fourth quarter of 2012 to 25.8% in the first quarter of 2013. The EIA's currently estimates electricity consumption in 2013 to be approximately flat as compared to the estimated consumption for 2012.

Due to elevated crude oil prices, domestic drilling activity for oil is at high levels and successful oil wells are producing natural gas as a by-product, which as indicated above, contributes to higher natural gas production despite extremely low prices. According to industry sources, the total domestic oil rig count is up over 31% in September 2012 compared to September 2011.

Future price declines for oil, NGLs and natural gas would negatively impact our future revenues, earnings and liquidity, and could result in ceiling test write-downs of the carrying value of our oil and natural gas properties, reductions in proved reserves, issues with financial ratio compliance, and a reduction of the borrowing base associated with our Credit Agreement, depending on the severity of such declines. If those events were to occur and were significant, the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry may be limited.

Many proposed changes in laws, regulations, guidance and policy continue to affect our industry. The process for obtaining offshore drilling permits, especially deepwater drilling permits, has expanded and lengthened in the past few years. The most significant regulation changes in the last two years are related to potential environmental impacts, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. These new regulations and increased review processes increase both the time to obtain drilling permits and the cost of operations. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time.

Results of Operations

The following tables set forth selected financial and operating data for the
periods indicated (all values are net to our interest unless indicated
otherwise):



                                                                 Three Months Ended                                          Nine Months Ended
                                                                  September 30, (1)                                          September 30, (1)
                                                  2012           2011          Change           %             2012          2011           Change           %
                                                                             (In thousands, except percentages and per share data)
Financial:
Revenues:
Oil                                             $ 138,034      $ 155,719      $ (17,685 )       (11.4 )%    $ 461,846     $ 466,493      $   (4,647 )       (1.0 )%
NGLs                                               12,468         28,250        (15,782 )       (55.9 )%       64,793        70,907          (6,114 )       (8.6 )%
Natural gas                                        35,054         61,174        (26,120 )       (42.7 )%      109,174       170,753         (61,579 )      (36.1 )%
Other                                                 390            228            162          71.1 %         1,532           995             537         54.0 %

Total revenues                                    185,946        245,371        (59,425 )       (24.2 )%      637,345       709,148         (71,803 )      (10.1 )%
Operating costs and expenses:
Lease operating expenses                           53,411         58,899         (5,488 )        (9.3 )%      170,349       159,901          10,448          6.5 %
Production taxes                                    1,353          1,050            303          28.9 %         4,174         2,183           1,991         91.2 %
Gathering and transportation                        2,810          4,853         (2,043 )       (42.1 )%       11,140        13,203          (2,063 )      (15.6 )%
Depreciation, depletion, amortization and
accretion                                          77,462         84,455         (6,993 )        (8.3 )%      251,894       241,917           9,977          4.1 %
General and administrative expenses                18,691         18,104            587           3.2 %        62,793        54,235           8,558         15.8 %
Derivative (gain) loss                             24,659        (17,323 )       41,982            NM          14,421       (10,815 )        25,236           NM

Total costs and expenses                          178,386        150,038         28,348          18.9 %       514,771       460,624          54,147         11.8 %

Operating income                                    7,560         95,333        (87,773 )       (92.1 )%      122,574       248,524        (125,950 )      (50.7 )%
Interest expense, net of amounts capitalized       11,408         11,558           (150 )        (1.3 )%       33,510        30,259           3,251         10.7 %
Loss on extinguishment of debt (2)                     -           2,031         (2,031 )          NM              -         22,694         (22,694 )         NM
Other income                                          202              6            196            NM             210            22             188           NM

Income (loss) before income tax expense
(benefit)                                          (3,646 )       81,750        (85,396 )      (104.5 )%       89,274       195,593        (106,319 )      (54.4 )%
Income tax expense (benefit)                       (2,175 )       28,822        (30,997 )      (107.5 )%       33,959        68,841         (34,882 )      (50.7 )%

Net income (loss)                               $  (1,471 )    $  52,928      $ (54,399 )      (102.8 )%    $  55,315     $ 126,752      $  (71,437 )      (56.4 )%


Basic and diluted earnings (loss) per common
share                                           $   (0.02 )    $    0.70      $   (0.72 )      (102.9 )%    $    0.73     $    1.68      $    (0.95 )      (56.5 )%

(1) In the second quarter of 2011, we acquired the Yellow Rose Properties and, in the third quarter of 2011, we acquired the Fairway Properties.

(2) In 2011, we charged to expense repurchase premiums, deferred financing costs and other costs totaling $22.0 million related to the repurchase of $450.0 million in aggregate principal amount of our 8.25% Senior Notes due 2014 and expensed $0.7 million of deferred financing costs related to replacement of our revolving bank credit facility.

NM = percentage change not meaningful

                                                               Three Months Ended                                       Nine Months Ended
                                                               September 30, (1)                                        September 30, (1)
                                                 2012          2011         Change           %            2012          2011         Change          %
Operating:
Net sales volumes:
Oil (MBbls)                                        1,371         1,524          (153 )      (10.0 )%        4,361         4,495         (134 )       (3.0 )%
NGLs (MBbls)                                         451           501           (50 )      (10.0 )%        1,581         1,279          302         23.6 %
Natural gas (MMcf)                                11,401        14,332        (2,931 )      (20.5 )%       40,097        39,384          713          1.8 %
Total natural gas and oil (MBoe) (2)               3,722         4,414          (692 )      (15.7 )%       12,625        12,338          287          2.3 %
Total natural gas and oil (MMcfe) (2)             22,331        26,483        (4,152 )      (15.7 )%       75,749        74,025        1,724          2.3 %

Average daily equivalent sales (Boe/d) (2)        40,454        47,977        (7,523 )      (15.7 )%       46,076        45,193          883          2.0 %
Average daily equivalent sales (Mcfe/d) (2)      242,723       287,860       (45,137 )      (15.7 )%      276,455       271,156        5,299          2.0 %

Average realized sales prices (Unhedged):
Oil ($/Bbl)                                    $  100.68     $  102.14     $   (1.46 )       (1.4 )%    $  105.89     $  103.78     $   2.11          2.0 %
NGLs ($/Bbl)                                       27.66         56.43        (28.77 )      (51.0 )%        40.99         55.45       (14.46 )      (26.1 )%
Natural gas ($/Mcf)                                 3.07          4.27         (1.20 )      (28.1 )%         2.72          4.34        (1.62 )      (37.3 )%
Oil equivalent ($/Boe) (2)                         49.86         55.54         (5.68 )      (10.2 )%        50.36         57.40        (7.04 )      (12.3 )%
Natural gas equivalent ($/Mcfe) (2)                 8.31          9.26         (0.95 )      (10.3 )%         8.39          9.57        (1.18 )      (12.3 )%

Average realized sales prices (Hedged) (3):
Oil ($/Bbl)                                    $  100.05     $  101.54     $   (1.49 )       (1.5 )%    $  104.30     $  101.73     $   2.57          2.5 %
NGLs ($/Bbl)                                       27.66         56.43        (28.77 )      (51.0 )%        40.99         55.45       (14.46 )      (26.1 )%
Natural gas ($/Mcf)                                 3.07          4.27         (1.20 )      (28.1 )%         2.72          4.34        (1.62 )      (37.3 )%
Oil equivalent ($/Boe) (2)                         49.62         55.33         (5.71 )      (10.3 )%        49.81         56.65        (6.84 )      (12.1 )%
Natural gas equivalent ($/Mcfe) (2)                 8.27          9.22         (0.95 )      (10.3 )%         8.30          9.44        (1.14 )      (12.1 )%

Average per Mcfe ($/Mcfe) (2):
Lease operating expenses                       $    2.39     $    2.22     $    0.17          7.7 %     $    2.25     $    2.16     $   0.09          4.2 %
Gathering and transportation                        0.13          0.18         (0.05 )      (27.8 )          0.15          0.18        (0.03 )      (16.7 )%

Production costs                                    2.52          2.40          0.12          5.0 %          2.40          2.34         0.06          2.6 %
Production taxes                                    0.06          0.04          0.02         50.0 %          0.06          0.03         0.03        100.0 %
Depreciation, depletion, amortization and
accretion                                           3.47          3.19          0.28          8.8 %          3.33          3.27         0.06          1.8 %
General and administrative expenses                 0.84          0.68          0.16         23.5 %          0.83          0.73         0.10         13.7 %

                                               $    6.89     $    6.31     $    0.58          9.2 %     $    6.62     $    6.37     $   0.25          3.9 %


Total number of wells drilled (gross):
Offshore                                               1             2            (1 )      (50.0 )%            3             4           (1 )      (25.0 )%
Onshore                                               18            17             1          5.9 %            55            24           31        129.2 %

Total number of productive wells drilled
(gross):
Offshore                                               1             2            (1 )      (50.0 )%            3             4           (1 )      (25.0 )%
Onshore                                               18            16             2         12.5 %            55            23           32        139.1 %

(1) In the second quarter of 2011, we acquired the Yellow Rose Properties and, in the third quarter of 2011, we acquired the Fairway Properties.

(2) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.

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

Volume measurements:
Boe - barrel of oil equivalent             MMcf - million cubic feet
Boe/d - barrel of oil equivalent per day   MMcfe - million cubic feet equivalent
MBbls - thousand barrels for crude oil,    Mcfe/d - thousand cubic feet
condensate or NGLs                         equivalent per day
MBoe - thousand barrels of oil
equivalent

. . .