W&T Offshore Reports Fourth Quarter and Full Year 2010 Financial and Operational Results

Mar 02, 2011, 06:15 ET from W&T Offshore, Inc.

HOUSTON, March 2, 2011 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today announces financial and operational results for the fourth quarter and full year 2010.  Some of the highlights include:

  • Total proved reserve replacement was 231%.  Proved reserves increased 31% from 371.0 Bcfe to 485.4 Bcfe.  Oil and natural gas liquids comprise 47% of total proved reserves. Year-end 2010 proved developed reserves increased to 81% of total proved reserves from 76% in 2009.  Our PV-10 increased 68% over year-end 2009.  
  • During the fourth quarter, we acquired three deepwater properties from Shell Offshore Inc. at a cost of $10.49 per barrel equivalent or $1.75 per Mcfe for proved reserves.
  • For the full year 2010, net income increased by $305.8 million to $117.9 million from a net loss of ($187.9) million in 2009.  Earnings per share increased $4.09 per share to $1.58 per share in 2010 from a loss in 2009 of ($2.51) per share.  Earnings for the year 2010, adjusted to exclude special items, were $1.57 per share compared to a loss of ($1.10) in 2009.
  • Cash flow from operating activities for the full year 2010 increased $308.5 million, or 197%, to $464.8 million compared to $156.3 million in 2009.  Adjusted EBITDA increased by $108.8 million to $450.2 million in 2010 compared to $341.4 million in 2009 and Adjusted EBITDA margin increased to 64% in 2010 compared to 56% in 2009.
  • Earnings for the fourth quarter, adjusted to exclude special items, were $0.40 per share compared to $0.35 in the fourth quarter of the prior year.  Fourth quarter net income was $20.5 million and earnings per share were $0.27.
  • Drilled the successful Main Pass 108 E-3 well that found 300 feet of net vertical pay in six sands.  This is a conventional shelf exploration well and we have a 100% working interest.
  • After the close of the fourth quarter, the Company drilled two wells. One of the wells is an onshore well in Southeast Texas in which we own a 50% non-operated working interest.  The well found 22 feet of gas condensate pay, and we expect it to be online before the end of the first quarter of 2011.  The second well is the Main Pass 180 A-2 well in which we own a 100% working interest.  The well reached a total vertical depth of 13,950 feet and found approximately 91 feet of high quality gas sands in three separate zones.  

Tracy W. Krohn, Chairman and Chief Executive Officer, commented, "We had another great quarter with solid production, high realized oil prices, good earnings and cash flow.  We were able to increase reserves in 2010 with two different acquisitions, which we expect to lead to increased production in 2011 as a result.  We funded our entire capital expenditure program, including both acquisitions, with internally generated cash flow.  As a result, we did not have to increase our debt levels nor did we need to sell any equity to accomplish these transactions.  As we have historically indicated, we manage for cash and constantly seek acquisition and joint venture opportunities.  We believe there continue to be important growth opportunities in the market place that will make sense for us and allow us to grow reserves and production and increase shareholder value.  Our liquidity continues to be very strong, allowing us the ability to complete acquisitions when the right opportunity comes along."

Revenues, Net Income and EPS:  Net income for the fourth quarter of 2010 excluding special items was $29.6 million, or $0.40 per share.  This compares to $26.7 million, or $0.35 per common share, reported for the fourth quarter of 2009, excluding special items.  See the "Reconciliation of Net Income (Loss) to Net Income (Loss) Excluding Special Items" and related earnings per share, excluding special items table under "Non-GAAP Financial Information" at the back of this press release for a description of the special items.  

Net income for the fourth quarter of 2010 was $20.5 million, or $0.27 per common share, on revenues of $187.0 million, compared to net income of $64.0 million and earnings per share of $0.84 on revenues of $176.1 million for the same period in 2009.  Net income in the fourth quarter of 2009 benefitted from a one-time $38.4 million tax benefit due to tax legislation adopted in 2009.  The Worker, Homeownership and Business Assistance Act of 2009, which extended the net operating loss carry-back period from two years to five years, resulted in additional tax benefits to us.  Revenues were higher in the fourth quarter of 2010 due to higher realized oil prices and minimal changes in production.  

Net income for 2010 was $117.9 million, or $1.58 per share, on revenues of $705.8 million.  This compares to a net loss in 2009 of ($187.9) million, or ($2.51) loss per share, on revenues of $611.0 million.  Net income for the year 2010, excluding special items, was $116.7 million, or $1.57 per share.  For 2009, the net loss, excluding special items, was ($82.3) million, or ($1.10) loss per common share.  The dramatic increase in earnings between periods is primarily due to an increase in our average realized sales prices, mainly due to oil price increases, and a reduction in most of our expenses.  In addition, the 2009 period included a ceiling test impairment of $218.9 million.  For 2010, lease operating expenses ("LOE"), depreciation, depletion, amortization and accretion ("DD&A") and the derivative loss were all lower, the reasons for which are explained below.  

Cash Flow from Operating Activities and Adjusted EBITDA:  EBITDA and Adjusted EBITDA, and Adjusted EBITDA margin are non-GAAP financial measures and are defined and reconciled in "Non-GAAP Financial Information" later in this press release.  Adjusted EBITDA for the fourth quarter of 2010 was $121.6 million compared to $115.1 million during the fourth quarter of the prior year.  Adjusted EBITDA for the fourth quarter of 2010 benefitted from higher averaged realized sales prices.  

For 2010, Adjusted EBITDA was $450.2 million, an increase of 32% compared to $341.4 million for the year 2009.  Net cash provided by operating activities for the full year of 2010 was $464.8 million, a significant increase over the $156.3 million reported for the prior year.  The dramatic increase in cash flow was due to higher prices, lower operating expenses, a federal income tax refund of $99.8 million and insurance reimbursements of $65.5 million.  

Production and Prices:  During the fourth quarter of 2010, we sold 1.8 million barrels of oil and natural gas liquids at an average realized sales price of $77.27 per barrel and 11.9 Bcf of natural gas at an average realized sales price of $4.01 per Mcfe.  In total we sold 22.6 Bcfe at an average realized sales price of $8.23 per Mcfe compared to 22.9 Bcfe sold at an average price of $7.67 per Mcfe, in the fourth quarter of the prior year.  Production volumes were negatively affected in 2010 because of production shut in at our MP 108 field due to a third party pipeline outage that has continued since early June 2010.

For the year 2010, we sold 7.1 million barrels of oil and natural gas liquids at an average realized sales price of $71.65 per barrel and 44.7 Bcf of natural gas at an average realized sales price of $4.55 per Mcf.  In total we sold 87.0 Bcfe at an average realized sales price of $8.15 per Mcfe, compared to 94.8 Bcfe sold at an average price of $6.39 per Mcfe in 2009.  The 8% decline in production is largely attributable to divestitures completed in 2009, the production shut in at our MP 108 field, as well as natural reservoir declines, somewhat offset by partial year production from the newly acquired properties from Shell and Total.

Lease Operating Expenses:  For the fourth quarter of 2010, total LOE was $47.5 million, up slightly from $45.8 million reported in the prior year's fourth quarter.  Despite adding the Shell deepwater properties, most of the components of LOE were lower in 2010 compared to 2009 with the exception of one notable item.  Facilities costs, which is a component of LOE, increased $6.8 million, about 40% of which can be attributed to repairs to newly acquired properties, while the remainder relates to pipeline and compressor repairs and blast and paint work.  Also of note, for both the fourth quarter of 2010 and the fourth quarter of 2009, insurance reimbursements exceeded hurricane remediation costs that are included in LOE.  The reduction in LOE as a result of these items was greater in the fourth quarter of 2009 than the comparable 2010 amount.  Insurance premiums that are included in LOE decreased $3.4 million in the fourth quarter of 2010 compared to the fourth quarter of 2009 due to a policy renewal effective June 1, 2010 covering well control and hurricane damage.  

LOE for the year 2010 was $169.7 million, or $1.95 per Mcfe, down considerably from the $203.9 million, or $2.15 per Mcfe, reported for the prior year.  LOE decreased for the year 2010 due to the 2009 property divestitures and the significant reduction in hurricane repairs, net of insurance reimbursements in 2010 compared to 2009.  Included in lease operating expenses for 2010 is a net reduction to LOE of $11.7 million (insurance reimbursements exceeded hurricane remediation costs).  This compares to an increase to LOE of $18.4 million for hurricane remediation costs in excess of insurance reimbursements in the prior year.  Increases to LOE for the year were the costs to operate the new properties, higher workover expenditures associated with rig activity to perform certain workovers and greater facilities work associated with the new properties.

Depreciation, depletion, amortization and accretion: DD&A decreased to $73.6 million, or $3.25 per Mcfe, in the fourth quarter of 2010 compared to $78.3 million, or $3.42 per Mcfe, in the fourth quarter of the prior year.  DD&A for the year 2010 was $294.1 million, or $3.38 per Mcfe, compared to $342.5 million, or $3.61 per Mcfe, for the year 2009.  DD&A is lower due to lower production volumes and an increase in proved reserves.  

Capital Expenditures, Acquisitions and Operations Update:  For 2010, our capital expenditures excluding acquisitions were $178.7 million and our expenditures for acquisitions were $236.9 million.  Acquisitions included $115.0 million to acquire the Total properties and $121.9 million to acquire the Shell properties.  Other capital expenditures were made up of $60.2 million for exploration activities, $77.2 million for development activities and $41.4 million for seismic, leasehold and other costs.  Capital expenditures and acquisitions for 2010 were funded from cash flow from operating activities and cash on hand.  Capital expenditures in 2009 were $276.1 million, and no significant acquisitions were completed in 2009.  

During 2010, we participated in the drilling of six offshore and two onshore wells.  Five of the six offshore wells were successful, but neither of the onshore wells, which were both high risk but high potential exploration opportunities, were commercial.  All five of the successful wells were on the conventional shelf and four were exploration wells and one was a development well.  We operate three of the five successful wells.

Drilling Highlights:  In the fourth quarter of 2010, the Company drilled the Main Pass 108 E-3 well.  This well logged over 300 feet of net vertical pay in six sands.  This is a conventional shelf exploration well in which we own a 100% working interest.

After the close of the fourth quarter, the Company drilled two wells. One of the wells is an onshore well in Southeast Texas in which we own a 50% non-operated working interest.  The well found 22 feet of gas condensate pay, and we expect it to be online before the end of the first quarter of 2011.  The second well is the Main Pass 180 A-2 well in which we own a 100% working interest.  The well reached a total vertical depth of 13,950 feet and found approximately 91 feet of high quality gas sands in three separate zones.

Reserves:  At December 31, 2010, total proved reserves were 485.4 Bcfe, compared to proved reserves of 371.0 Bcfe at the end of 2009.  The 31% increase in proved reserves is primarily due to the newly acquired properties from Shell and Total, success with the drill bit and positive revisions, which are partially offset by production.  Year-end 2010 proved reserves are comprised of 53% natural gas and 47% oil and natural gas liquids based on a ratio of six Mcf to one barrel equivalent.  In accordance with guidelines established by the SEC, our proved reserves as of December 31, 2010 were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period January 2010 through December 2010.  The present value of our total proved reserves only, discounted at 10% (referred to as "PV-10"*) was $1.9 billion at December 31, 2010 excluding the effect of estimated asset retirement obligations.  PV-10, including estimated asset retirement obligations, was $1.5 billion.  This is based on average prices of $4.38 per Mcf for natural gas and $75.96 per Bbl for oil and natural gas liquids, adjusted for quality, transportation fees and regional price differentials.  The estimate of proved reserves is based on a reserve report prepared by Netherland, Sewell & Associates, Inc., the Company's independent petroleum consultant.

* The PV-10 value is a non-GAAP measure and is defined in the "Non-GAAP Financial Information" later in this press release.

The Company's proved reserves are summarized in the table below:

As of December 31, 2010

Total Equivalent Reserves

Oil and NGLs

Natural Gas

Natural Gas Equivalent

Barrel Equivalent

% of Total

Classification of Reserves

(MMBbls)

(Bcf)

(Bcfe)

(MMBoe)

Proved

Proved developed producing             

14.8

147.7

236.6

39.4

49%

Proved developed non-producing (1)      

12.2

81.4

154.7

25.8

32%

  Total proved developed               

27.0

229.1

391.3

65.2

81%

Proved undeveloped                   

11.2

27.2

 94.1

15.7

19%

  Total proved                        

38.2

256.3

485.4

80.9

100%

(1) Includes approximately 29.6 Bcfe of reserves that were shut in at December 31, 2010 due to two pipeline outages impacting several fields including our Main Pass 108 field.  We expect these reserves to be reclassified to producing in the first half of 2011.  

2010 Reserve Reconciliation:

Total Equivalent Reserves

  Oil and NGLs

  Natural Gas

Natural Gas Equivalent

Barrel Equivalent

(MMBbls)

 (Bcf)

   (Bcfe)

   (MMBoe)

Proved reserves as of December 31, 2009           

34.2

165.8

371.0

61.8

Revisions of previous estimates               

 1.0

 14.6

 20.2

 3.4

Extensions and discoveries                   

 1.7

 19.1

 29.2

 4.9

Purchases of minerals in place                

 8.4

101.5

152.0

25.3

Production                                 

 (7.1)

 (44.7)

 (87.0)

(14.5)

Proved reserves as of December 31, 2010           

38.2

256.3

485.4

80.9

As stated above, proved reserve replacement for 2010 was 231%.  Proved reserve replacement is a non-GAAP measure and is defined as the sum of revisions of previous estimates, extensions and recoveries, and purchases of mineral in place, divided by production.

2011 Capital Expenditures Budget:  Our capital expenditure budget for 2011 is $310 million excluding acquisitions.  The budget includes $161 million to drill and evaluate 14 wells, including 10 exploration and four development wells.  The 14 wells are comprised of five on the conventional shelf, one in the deepwater, two on the deep shelf and six onshore.  Three of the 14 wells are in progress.  The remainder of the budget is allocated to well completions, facilities capital, such as compressor projects at Tahoe (VK 783) and MP 108, recompletions, seismic and leasehold items.

Outlook:  The guidance for first quarter and full year 2011 represents the Company's best estimate of likely future results, and is affected by the factors described below in "Forward-Looking Statements."

Guidance for the first quarter and full year 2011 are shown in the table below.  Production guidance includes the planned build up from our capital budget.  

2011 Production and Cost Guidance:

Estimated Production

First Quarter 2011

Full-Year 2011

Oil and NGLs (MMBbls)

1.5 – 1.6

5.5 – 6.3

Natural gas (Bcf)

12.0 – 12.6

50.2 – 58.9

Total (Bcfe)

20.8 – 21.9

83.2 – 96.7

Total (MMBoe)

3.5 – 3.7

13.9 – 16.1

Operating Expenses ($ in millions, except as noted)

First Quarter 2011

Full-Year 2011

Lease operating expenses

$51– $57

$188 – $218

Gathering, transportation & production taxes

$5 – $7

$22– $25

General and administrative

$19 – $21

$67 – $78

Income tax rate

35%

35%

Conference Call Information:  W&T will hold a conference call to discuss financial and operational results on Wednesday, March 2, 2011 at 10:00 a.m. Eastern Time.  To participate, dial (480) 629-9692 a few minutes before the call begins.  The call will also be broadcast live over the Internet from the Company's website at www.wtoffshore.com.  A replay of the conference call will be available approximately two hours after the end of the call until March 9, 2011, and may be accessed by calling (303) 590-3030 and using the pass code 4400979#.

About W&T Offshore

W&T Offshore is an independent oil and natural gas company focused primarily in the Gulf of Mexico, including exploration in the deepwater and deep shelf regions, where it has developed significant technical expertise. W&T has grown through acquisition, exploitation and exploration and holds working interests in approximately 67 fields in federal and state waters and a majority of its daily production is derived from wells it operates.  For more information on W&T Offshore, please visit its Web site at www.wtoffshore.com.  

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. No assurance can be given, however, that these events will occur. These statements are subject to risks and uncertainties that could cause actual results to differ materially including, among other things, market conditions, oil and gas price volatility, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, competition, the success of our risk management activities, governmental regulations, uncertainties and other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2009 and subsequent Form 10-Q reports found at (www.sec.gov).

Contacts:

Janet Yang, Finance Manager

investorrelations@wtoffshore.com

713-297-8024

Danny Gibbons, SVP & CFO

jgibbons@wtoffshore.com

713-624-7326

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Income (Loss)

(Unaudited)

Three Months Ended

Twelve Months Ended

December 31,

December 31,

2010

2009

2010

2009

(In thousands, except per share data)

Revenues

$

186,956

$

176,100

$

705,783

$

610,996

Operating costs and expenses:

Lease operating expenses

47,476

45,792

169,670

203,922

Gathering, transportation costs and production taxes

3,970

3,299

17,678

15,163

Depreciation, depletion and amortization

66,545

72,634

268,415

308,076

Asset retirement obligation accretion

7,009

5,700

25,685

34,461

Impairment of oil and natural gas properties (1)

-

-

-

218,871

General and administrative expenses

15,147

11,065

53,290

42,990

Derivative loss

12,756

2,675

4,256

7,372

Total costs and expenses

152,903

141,165

538,994

830,855

Operating income (loss)

34,053

34,935

166,789

(219,859)

Interest expense:

Incurred

10,782

11,404

43,101

46,749

Capitalized

(1,305)

(1,284)

(5,395)

(6,662)

Loss on extinguishment of debt

-

-

-

2,926

Interest income

78

80

710

842

Income (loss) before income tax expense (benefit)

24,654

24,895

129,793

(262,030)

Income tax expense (benefit)

4,135

(39,059)

11,901

(74,111)

Net income (loss)

$

20,519

$

63,954

$

117,892

$

(187,919)

Basic and diluted earnings (loss) per common share

$

0.27

$

0.84

$

1.58

$

(2.51)

Weighted average common shares outstanding

73,736

74,148

73,685

74,852

Consolidated Cash Flow Information

Net cash provided by operating activities

$

71,895

$

64,395

$

464,772

$

156,266

Investment in oil and natural gas properties

171,637

169

415,653

276,134

Other Financial Information

EBITDA

$

107,607

$

113,269

$

460,889

$

338,623

Adjusted EBITDA

121,647

115,084

450,206

341,361

(1) The carrying amount of our oil and natural gas properties was written down by $218.9 million as of March 31, 2009 through application of the full cost ceiling limitation as prescribed by the SEC, primarily as a result of lower natural gas prices at March 31, 2009, as compared to December 31, 2008.

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)

Three Months Ended

Twelve Months Ended

December 31,

December 31,

2010

2009

2010

2009

Net sales:

Natural gas (MMcf)

11,856

11,696

44,713

51,621

Oil (MBbls)

1,796

1,871

7,053

7,197

Total natural gas and oil (MBoe) (1)

3,772

3,820

14,505

15,801

Total natural gas and oil (MMcfe) (2)

22,634

22,922

87,032

94,806

Average daily equivalent sales (MBoe/d)

41.0

41.5

39.7

43.3

Average daily equivalent sales (MMcfe/d)

246.0

249.2

238.4

259.7

Average realized sales prices (Unhedged):

Natural gas ($/Mcf)

$

4.01

$

3.92

$

4.55

$

3.97

Oil ($/Bbl)

77.27

69.47

71.65

55.67

Barrel of oil equivalent ($/Boe)

49.39

46.02

48.87

38.32

Natural gas equivalent ($/Mcfe)

8.23

7.67

8.15

6.39

Average realized sales prices (Hedged): (3)

Natural gas ($/Mcf)

$

4.18

$

3.90

$

4.71

$

3.96

Oil ($/Bbl)

76.87

69.47

71.42

55.67

Barrel of oil equivalent ($/Boe)

49.73

45.96

49.25

38.30

Natural gas equivalent ($/Mcfe)

8.29

7.66

8.21

6.38

Average per Boe ($/Boe):

Lease operating expenses

$

12.59

$

11.99

$

11.70

$

12.91

Gathering and transportation costs and production taxes

1.05

0.86

1.22

0.96

Depreciation, depletion, amortization and accretion

19.50

20.50

20.28

21.68

General and administrative expenses

4.02

2.90

3.67

2.72

Net cash provided by operating activities

19.06

16.86

32.04

9.89

Adjusted EBITDA

32.25

30.12

31.04

21.60

Average per Mcfe ($/Mcfe):

Lease operating expenses

$

2.10

$

2.00

$

1.95

$

2.15

Gathering and transportation costs and production taxes

0.18

0.14

0.20

0.16

Depreciation, depletion, amortization and accretion

3.25

3.42

3.38

3.61

General and administrative expenses

0.67

0.48

0.61

0.45

Net cash provided by operating activities

3.18

2.81

5.34

1.65

Adjusted EBITDA

5.37

5.02

5.17

3.60

(1) One million barrels of oil equivalent (MMBoe), one thousand barrels of oil equivalent (Mboe) and one barrel of oil equivalent (Boe) are determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas (totals may not add due to rounding).

(2) One billion cubic feet equivalent (Bcfe), one million cubic feet equivalent (MMcfe) and one thousand cubic feet equivalent (Mcfe) are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids (totals may not add due to rounding).  The conversion ratios do not assume price equivalency, and the price per Mcfe for oil and natural gas liquids may differ significantly from the price per Mcf for natural gas.

(3) Data for 2010 and 2009 includes the effects of our commodity derivative contracts that did not qualify for hedge accounting.

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Unaudited)

December 31,

December 31,

2010

2009

(In thousands, except

share data)

Assets

Current assets:

Cash and cash equivalents

$

28,655

$

38,187

Receivables:

  Oil and natural gas sales

79,911

54,978

  Joint interest and other

25,415

51,312

  Insurance

1,014

30,543

  Income taxes

-

85,457

     Total receivables

106,340

222,290

Deferred income taxes

5,784

-

Prepaid expenses and other assets

23,426

28,777

Total current assets

164,205

289,254

Property and equipment – at cost:

Oil and natural gas properties and equipment (full cost method, of which $65,419 at 

December 31, 2010 and $77,301 at December 31, 2009 were excluded from

amortization)

5,225,582

4,732,696

Furniture, fixtures and other

15,841

15,080

Total property and equipment

5,241,423

4,747,776

Less accumulated depreciation, depletion and amortization

4,021,395

3,752,980

Net property and equipment

1,220,028

994,796

Restricted deposits for asset retirement obligations

30,636

30,614

Deferred income taxes

2,819

5,117

Other assets

6,406

7,052

Total assets

$

1,424,094

$

1,326,833

Liabilities and Shareholders’ Equity

Current liabilities:

Accounts payable

$

80,442

$

115,683

Undistributed oil and natural gas proceeds

25,240

32,216

Asset retirement obligations

92,575

117,421

Accrued liabilities

25,827

13,509

Income taxes

17,552

-

Deferred income taxes

-

5,117

Total current liabilities

241,636

283,946

Long-term debt

450,000

450,000

Asset retirement obligations, less current portion

298,741

231,379

Other liabilities

11,974

2,558

Commitments and contingencies  

Shareholders’ equity:

Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,343,520

issued and 74,474,347 outstanding at December 31, 2010;  77,579,968 issued and

74,710,795 outstanding at December 31, 2009

1

1

Additional paid-in capital

377,529

373,050

Retained earnings

68,380

10,066

Treasury stock, at cost

(24,167)

(24,167)

Total shareholders’ equity

421,743

358,950

Total liabilities and shareholders’ equity

$

1,424,094

$

1,326,833

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(Unaudited)

Twelve Months Ended

December 31,

2010

2009

(In thousands)

Operating activities:

Net income (loss)

$

117,892

$

(187,919)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion, amortization and accretion

294,100

345,637

Impairment of oil and natural gas properties

-

218,871

Amortization of debt issuance costs and discount on indebtedness

1,338

1,838

Loss on extinguishment of debt

-

2,817

Share-based compensation

5,533

6,380

Derivative loss

4,256

7,372

Cash payments on derivative settlements

874

(6,679)

Deferred income taxes

(8,266)

(346)

Changes in operating assets and liabilities

49,045

(232,703)

Other

-

998

Net cash provided by operating activities

464,772

156,266

Investing activities:

Acquisition of property interests

(236,944)

(2,421)

Investment in oil and natural gas properties and equipment

(178,709)

(273,713)

Proceeds from sales of oil and natural gas properties and equipment

1,420

32,226

Proceeds from insurance

-

6,916

Purchases of furniture, fixtures and other

(760)

(705)

Net cash used in investing activities

(414,993)

(237,697)

Financing activities:

Borrowings of long-term debt

627,500

205,441

Repayments of long-term debt

(627,500)

(410,941)

Dividends to shareholders

(59,609)

(9,158)

Repurchases of common stock

-

(24,167)

Other

298

891

Net cash used in financing activities

(59,311)

(237,934)

Decrease in cash and cash equivalents

(9,532)

(319,365)

Cash and cash equivalents, beginning of period

38,187

357,552

Cash and cash equivalents, end of period

$

28,655

$

38,187

W&T OFFSHORE, INC. AND SUBSIDIARIES

Non-GAAP Financial Information

Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP.  These non-GAAP financial measures are "Adjusted Net Income," "EBITDA," "Adjusted EBITDA," "Adjusted EBITDA Margin," and "PV-10."  Our management uses these non-GAAP financial measures in its analysis of our performance.  These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP performance measures, which may be reported by other companies.  We calculate Adjusted EBITDA margin by dividing Adjusted EBITDA for the period presented by total revenues for the same period.  PV-10 is a term used in the industry that is not a defined term in generally accepted accounting principles. We define PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our independent petroleum consultant using a discount rate of 10%.  This amount includes projected revenues, estimated production costs and estimated future development costs.  PV-10 excludes cash flows for asset retirement obligations, general and administrative expenses, derivatives, debt service and income taxes.  PV-10 including estimated asset retirement obligations uses a discount factor of 10% to compute the present value of the estimated asset retirement obligations.

Reconciliation of Net Income (Loss) to Net Income (Loss) Excluding Special Items

"Net Income (Loss) Excluding Special Items" does not include the unrealized derivative (gain) loss, the loss on extinguishment of debt, the impairment of oil and gas properties and associated tax effects and tax impact of the new tax legislation.  Net Income (Loss) excluding special items is presented because the timing and amount of these items cannot be reasonably estimated and affect the comparability of operating results from period to period, and current periods to prior periods.

Three Months Ended

Twelve Months Ended

December 31,

December 31,

2010

2009

2010

2009

(In thousands, except per share amounts)

(Unaudited)

Net income (loss)

$

20,519

$

63,954

$

117,892

$

(187,919)

Royalty relief recoupment, net of DD&A expense

-

-

(16,003)

-

Transportation allowance for deepwater production

-

(292)

4,687

(5,558)

Unrealized commodity derivative loss

14,040

2,107

9,511

5,370

Loss on extinguishment of debt

-

-

-

2,926

Impairment of oil and natural gas properties

-

-

-

218,871

Income tax adjustment for above items at statutory rate

(4,914)

(635)

632

(77,563)

Income tax impact of new legislation (1)

-

(38,407)

-

(38,407)

Net income (loss) excluding special items

$

29,645

$

26,727

$

116,719

$

(82,280)

Basic and diluted earnings (loss) per common share, excluding special items

$

0.40

$

0.35

$

1.57

$

(1.10)

(1) The Worker, Homeownership and Business Assistance Act of 2009.

Reconciliation of Net Income to Adjusted EBITDA

We define EBITDA as net income (loss) plus income tax expense (benefit), net interest expense, depreciation, depletion, amortization, accretion and impairment of oil and gas properties.  We believe the presentation of EBITDA and Adjusted EBITDA provide useful information regarding our ability to service debt and to fund capital expenditures and help our investors understand our operating performance and make it easier to compare our results with those of other companies that have different financing, capital and tax structures.  Adjusted EBITDA excludes the unrealized gain or loss related to our commodity derivative contracts, loss on extinguishment of debt, royalty relief recoupment and adjustments related to a transportation allowance for deepwater production.  Although not prescribed under generally accepted accounting principles, we believe the presentation of EBITDA and Adjusted EBITDA are relevant and useful because they help our investors understand our operating performance and make it easier to compare our results with those of other companies that have different financing, capital and tax structures.  EBITDA and Adjusted EBITDA should not be considered in isolation from or as a substitute for net income, as an indication of operating performance or cash flows from operating activities or as a measure of liquidity.  EBITDA and Adjusted EBITDA, as we calculate them, may not be comparable to EBITDA and Adjusted EBITDA measures reported by other companies.  In addition, EBITDA and Adjusted EBITDA do not represent funds available for discretionary use.  The following table presents a reconciliation of our consolidated net income (loss) to consolidated EBITDA and Adjusted EBITDA.

Three Months Ended

Twelve Months Ended

December 31,

December 31,

2010

2009

2010

2009

(In thousands)

(Unaudited)

Net income (loss)

$

20,519

$

63,954

$

117,892

$

(187,919)

Income tax expense (benefit)

4,135

(39,059)

11,901

(74,111)

Net interest expense

9,399

10,040

36,996

39,245

Depreciation, depletion, amortization and accretion

73,554

78,334

294,100

342,537

Impairment of oil and natural gas properties

-

-

-

218,871

EBITDA

107,607

113,269

460,889

338,623

Adjustments:

Unrealized commodity derivative loss

14,040

2,107

9,511

5,370

Royalty relief recoupment

-

-

(24,881)

-

Transportation allowance for deepwater production

-

(292)

4,687

(5,558)

Loss on extinguishment of debt

-

-

-

2,926

Adjusted EBITDA

$

121,647

$

115,084

$

450,206

$

341,361

SOURCE W&T Offshore, Inc.



RELATED LINKS

http://www.wtoffshore.com