W&T Offshore Reports Fourth Quarter And Full-Year 2013 Financial Results, 2013 Proved Reserves, And 2014 Production And Expense Guidance

HOUSTON, March 6, 2014 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today reported its 2013 financial and operational results for the fourth quarter and full year, 2013 proved reserves, and 2014 production and expense guidance.  Some of the highlights include:

  • Extensions and discoveries of proved reserves for 2013 were 20.2 million barrels of oil equivalent ("Boe") or 121.0 billion cubic feet of natural gas equivalent ("Bcfe"), primarily associated with our successful drilling and development program.  Our 2013 year-end proved reserves were 117.7 million barrels of oil equivalent ("Boe").
  • At our Yellow Rose field in the Permian Basin of west Texas, production grew over 46% from the prior year and proved reserves at year end 2013 increased more than 20% over the prior year.
  • Exploration discoveries were made offshore on the conventional shelf at our Ship Shoal 349 field ("Mahogany") and at our Main Pass 108 field.  In the deepwater Gulf of Mexico, we made two exploration discoveries at Mississippi Canyon 782 ("Dantzler") and Mississippi Canyon 699 ("Troubadour"), both of which complement our 2012 discovery at Mississippi Canyon 698 ("Big Bend"). 
  • Additional deepwater production and reserves were acquired from a subsidiary of Callon Petroleum Company ("Callon") in the fourth quarter of 2013 providing immediate production and multiple deepwater drilling opportunities at the Mississippi Canyon 582 field ("Medusa"). 
  • Success with the drill bit was greater than 90% for the year.  Exploration drilling resulted in eight of nine wells being discoveries, while development drilling was 100% with all 37 wells drilled being commercially successful.
  • For the fourth quarter of 2013, production volumes were up 14.4% over the fourth quarter of 2012.  Production volumes averaged 56,100 Boe per day, or 336.4 million cubic feet of natural gas equivalent ("MMcfe") per day.  Production volumes were split 35% oil, 11% natural gas liquids ("NGLs") and 54% natural gas. 
  • Revenues for the fourth quarter of 2013 were $244.9 million up 3.3% over the fourth quarter of 2012.
  • For the full year 2013, oil production volumes increased 16.3% driving an overall increase in production volumes of 5.0% compared to the prior year.
  • Revenues for the full year 2013 were $984.1 million, an increase of $109.6 million or 12.5% over 2012 due to higher oil production and higher natural gas prices.   
  • Net income for the full year 2013 was $51.3 million and earnings were $0.68 per share.
  • For the full year, adjusted EBITDA (as described below) was $598.1 million, an increase of $55.9 million or 10.3% over the year 2012.  Net cash provided by operating activities for 2013 was $561.4 million, an increase of $176.2 million or 45.8% over 2012. 

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "2013 was a transition year for the company, yet we replaced over 100% of production and our operating cash flow increased significantly on much higher oil production.  We were able to increase production in 2013 despite various pipeline and platform outages and inclement weather during the latter part of the year.  Production deferrals attributable to third-party pipeline outages, platform maintenance, and various other issues were approximately 13.0 Bcfe during 2013.   

"Our success rate with the drill bit in 2013 was well above 90% with two high impact deepwater discoveries at Dantzler and Troubadour which complement our late 2012 deepwater exploration discovery at Big Bend.  The benefit of these significant discoveries, in terms of reserve additions and production, should begin to become visible in the beginning of 2015.  In 2014, we will continue working towards the company's goal of expanding through organic growth and acquisitions."

Production, Revenues and Price: For the full year 2013, total production volumes were up 5% over 2012 due to a 16.3% increase in crude oil production.  This was accomplished despite significant third party pipeline and platform outages and a loss of production during the fourth quarter in the Permian Basin due to severe weather.  Production volumes increased roughly 14.4% when comparing the fourth quarter of 2013 to the same period in 2012. 

Revenues for the fourth quarter of 2013 were $244.9 million compared to $237.1 million in the fourth quarter of 2012.  During the fourth quarter of 2013, we sold 1.8 million barrels of oil, 0.6 million barrels of NGLs and 16.8 Bcf of natural gas as compared to 1.7 million barrels of oil, 0.5 million barrels of NGLs and 13.7 Bcf of natural gas during the same period in 2012.  Average realized sales price was $94.11 per barrel for oil, $39.78 per barrel for NGLs and $3.15 per Mcf for natural gas in the fourth quarter of 2013.  On a combined basis, we sold 5.2 million Boe at an average realized sales price of $47.33 per Boe compared to 4.5 million Boe sold at an average realized sales price of $52.51 per Boe in the fourth quarter of 2012. 

For the full year 2013, revenues were $984.1 million, which represents an increase of $109.6 million or 12.5% over 2012.  Revenues were higher in 2013 compared to 2012 due to increased oil production and an increase in natural gas prices.  Revenues from oil and NGLs as a percent of our total revenues were 80.5% for 2013.  NGLs realized sales prices as a percent of oil realized prices were 34.2% for 2013.  During 2013 we sold 7.0 million barrels of oil, 2.1 million barrels of NGLs, and 53.3 Bcf of natural gas as compared to 6.0 million barrels of oil, 2.1 million barrels of NGLs, and 53.8 Bcf of natural gas sold during 2012.  On a combined basis, we sold 18.0 million Boe at an average realized sales price of $54.58 per Boe compared to 17.1 million Boe sold at an average realized sales price of $50.93 per Boe during 2012.

Our reported fourth quarter 2013 production volumes were affected by a cumulative volume adjustment associated with previous periods.  In January 2014, the Company identified an erroneous MMBtu conversion factor it had been receiving from a third party that had the effect of understating natural gas production at our Viosca Knoll 783 field ("Tahoe") since we acquired the field in 2011.  The correction of this erroneous conversion factor did not affect revenues, operating cash flows or royalty payments to the federal government but did impact reported natural gas production volumes and the resultant calculation of depletion expense.   We determined that the impact on earnings reported for prior annual periods was not material to 2011 and 2012 results, and the adjustment was fully recognized in the fourth quarter of 2013.  Thus, fourth quarter 2013 results include a one-time increase in production of 2.6 Bcf (with no corresponding increase in revenue) resulting from using the correct conversion factor for the annual periods of 2011, 2012 and the first three quarters of 2013.  The impact of the volume understatement on 2011, 2012 and the first nine months of 2013 were 0.9 Bcf, 1.0 Bcf, and 0.7 Bcf, respectively.

Excluding the cumulative effect of this volume adjustment, production would have been 4.7 million Boe for the fourth quarter of 2013, or 51,300 Boe per day, and our average realized sales price would have been $51.74 per Boe.  For the full year 2013, production would have been 17.7 million Boe, or 48,400 Boe per day, and our average realized sales price would have been $55.55 per Boe. 

Cash Flow from Operating Activities and Adjusted EBITDA: EBITDA and Adjusted EBITDA are non-GAAP measures and are defined in the "Non-GAAP Financial Measures" section at the end of this press release.  Adjusted EBITDA for the full year 2013 was $598.1 million, compared to $542.3 million for 2012.  Adjusted EBITDA was higher for 2013 primarily due to increased oil production.  Our Adjusted EBITDA margin was 61% for 2013, compared to 62% in 2012.  For the year 2013, cash flows from operating activities were $561.4 million, up $176.2 million from 2012, virtually all of which is due to changes in working capital (resulting primarily from an income tax refund, increased receivables collections, lower spending on the settlement of our asset retirement obligations ("ARO") and higher payables associated with increased activities).    

Lease Operating Expenses ("LOE"):  For the fourth quarter of 2013, LOE, which includes base LOE, insurance premiums, workovers, facilities expenses, and hurricane remediation costs net of insurance claims, was $75.9 million compared to $61.9 million in the fourth quarter of 2012.  Base LOE increased $6.1 million in the latest quarter due to lower production handling fees (that are treated as an offset to LOE), continued growth in the well count at our Yellow Rose field, settlement of audit claims on one of our platforms and the acquisition of the properties from Callon.  Workover expenses were up $11.4 million during the fourth quarter of 2013 primarily due to an unplanned workover on the A-12 well at Mahogany to resolve a casing pressure issue. This workover resulted in additional LOE in the fourth quarter of approximately $13.6 million.   Insurance premiums and hurricane repairs were lower by $2.2 million and $1.0 million, respectively, compared to the same period in 2012.  Facilities expenses were higher by $0.6 million, roughly comparable to those in the fourth quarter of 2012. 

For the full year 2013, LOE was $270.8 million compared to $232.3 million for 2012.  Base LOE rose by $14.5 million, workovers were up $25.0 million, and facilities expenses were up $5.1 million.  Conversely, insurance premiums were lower by $4.6 million, hurricane repairs were lower by $0.7 million, and the net effect of insurance reimbursements lowered costs by $0.8 million.  The increase in base LOE was primarily attributable to the acquisition of various properties from Newfield Exploration Co. in the fourth quarter of 2012, expanded onshore operations, and ad valorem tax refunds received in 2012, partially offset by increased processing fees in 2013 charged to third parties.  The increase in workover expense was primarily the result of rig workovers on two offshore wells at Mahogany and Main Pass 69, and increased workover activity at our Yellow Rose field.  Facilities maintenance expense increased due to a planned shutdown for maintenance at our Yellowhammer plant.

Depreciation, depletion, amortization and accretion ("DD&A"):  DD&A for the fourth quarter of 2013 was $138.6 million as compared to $104.3 million for the fourth quarter of 2012.  For the full year 2013, DD&A was $451.5 million, up from $356.2 million in 2012.  The increase in DD&A for the fourth quarter is due to higher production, the out-of-period volume adjustment discussed above that impacted DD&A, an increase in future development costs associated with increased proved undeveloped reserves, additional exploration and development capital expenditures that were added to the full cost pool, as well as an increase in estimates of asset retirement obligation ("ARO"). 

Net Income & EPS:  As a result of the increase in LOE and DD&A discussed above, our operating results for the fourth quarter of 2013 resulted in a net loss of $11.9 million, or a loss of $0.16 per common share, compared to net income of $16.7 million, or $0.21 per common share for the same period in 2012.  Operating results for the fourth quarter of 2013, excluding special items, was a loss of $6.8 million, or a loss of $0.09 per common share.  For the full year 2013, we reported net income of $51.3 million on $984.1 million of revenues and reported earnings of $0.68 per share, compared to net income of $72.0 million and earnings of $0.95 per share in 2012.  See the "Reconciliation of Net Income to Net Income Excluding Special Items" and related earnings per share, excluding special items in the table under "Non-GAAP Financial Information" at the back of this press release for a description of the special items. 

Capital Expenditures Update:  Our total capital expenditures for 2013 were $634.4 million, comprised of $552.0 million for oil and gas expenditures and $82.4 million for acquisitions.  Capital expenditures for oil and gas properties consisted of $198.7 million for exploration activities, $308.3 million for development activities, and $45.0 million for seismic, leasehold, and other costs.  Acquisition activity was primarily focused on certain oil and gas leasehold interests from Callon, discussed earlier in this press release.  The acquisition was funded from cash on hand and our revolving bank credit facility.  

Also during the fourth quarter of 2013, the Company renewed its revolving bank credit facility with more favorable terms and extended the maturity date to October of 2018 while the borrowing base remained at $800 million.  As of December 31, 2013, the undrawn borrowing capacity on our revolving bank credit facility was $509.6 million

2014 Capital Expenditure Budget: As previously announced, we have set our 2014 capital budget at $450 million and provided details of certain 2014 exploration and development projects.  As reported, approximately 42% of the budget is expected to be for exploratory activities, 52% for oil-focused development activities, and the remaining 6% will be utilized for seismic and other activities.  We expect that 68% of the 2014 budget will be for projects in the Gulf of Mexico, and 32% for projects onshore in Texas.  Approximately one-third of the budget is focused on deepwater activity in the Gulf of Mexico, including significant capital for development of Big Bend, and a planned deepwater well at Medusa.  Our continued success at Mahogany will keep a rig running throughout 2014 and into 2015 with the current drilling of the A-15 well, followed by two additional wells.  Onshore, we have budgeted for the drilling of approximately 20 vertical wells, many of which will continue to prove up our 40 acre downspacing, and seven horizontal wells which will focus on the Wolfcamp "B" and potentially test other benches.   

2013 Proved Reserves (1):  As previously announced, total proved reserves were 117.7 MMBoe (705.9 Bcfe) at December 31, 2013, up from 117.5 MMBoe (705.1 Bcfe) at December 31, 2012.  Classified by product, our reserves at December 31, 2013 were 50% oil, 13% NGLs and 37% natural gas.    Successful exploration and development drilling during the year coupled with 40 acre down-spacing onshore and joint interest activity resulted in extensions and discoveries of 20.2 MMBoe (121.0 Bcfe).  Extensions and discoveries occurred primarily at Yellow Rose, Mahogany, and Big Bend.  For Yellow Rose, the increase in proved reserves was primarily due to the successful completion of six exploration wells, the further addition of proved undeveloped locations in the field resulting from 40 acre down-spacing, and other drilling activity by us and others and the purchase of additional acreage in the field.  At Mahogany, the increase in proved reserves resulted from the successful drilling and completion of the A-14 exploratory well.  New proved reserves were also booked for our deepwater discovery at Big Bend, although we believe these might represent only a small portion of what we would expect to book in future periods.  Successful exploration wells at both Troubadour and Dantzler were not reflected in our 2013 proved reserves as neither project was sanctioned for development prior to year end.  Our proved reserves also increased with the acquisition of Medusa, which added approximately 2.1 MMBoe (12.7 Bcfe) of proved reserves, comprised of approximately 67% oil and 33% natural gas.   Finally, activity in 2013 allowed conversion of approximately 47% of our proved undeveloped reserves existing at December 31, 2012 to proved developed reserves as of December 31, 2013.

(1) Our proved reserves were estimated by NSAI, our independent petroleum consultant.  In accordance with guidelines established by the SEC, our proved reserves as of December 31, 2013 were determined to be economically producible under existing economic conditions, which requires the use of the unweighted arithmetic average of the first-day-of-the-month price for oil and gas for the period January 2013 through December 2013.  For 2013, proved reserves were calculated using average prices of $99.65 per barrel for oil, $35.21 per barrel for natural gas liquids and $3.80 per Mcf for natural gas, as adjusted for energy content for natural gas, quality, transportation fees and regional price differentials. 

2014 Outlook

Our guidance for the first quarter and full year 2014 is provided in the table below and represents the Company's best estimate of the range of likely future results, and is affected by the factors described below in "Forward-Looking Statements." 

Estimated Production

First Quarter

2014

 Full-Year

2014

Oil and NGLs  (MMBbls)

2.2 – 2.5

9.0 – 9.9

Natural gas (Bcf)

12.3 – 13.6

48.7 – 53.8

Total (Bcfe)

25.7 – 28.4

  102.6 – 113.4

Total (MMBoe)

4.3 – 4.7

17.1 – 18.9




Operating Expenses          

($ in millions)

First Quarter

2014

Full-Year

2014

Lease operating expenses

$61 – $67

$243 – $269

Gathering, transportation &    production taxes

$6 – $7

$25 – $28

General and administrative

$23 – $25

$85 – $93

Income tax rate (100% deferred)

36%

36%

 

Conference Call Information:  W&T will hold a conference call to discuss our financial and operational results on Friday, March 7, 2014, at 9:30 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 14, 2014, and may be accessed by calling 303-590-3030 and using the pass code 4665733#.

About W&T Offshore
W&T Offshore, Inc. is an independent oil and natural gas producer with operations offshore in the Gulf of Mexico and onshore in both the Permian Basin of West Texas and in East Texas.  We have grown through acquisitions, exploration and development and currently hold working interests in approximately 67 offshore fields in federal and state waters (62 producing and five fields capable of producing).  W&T currently has under lease approximately 1.3 million gross acres, including approximately 0.6 million gross acres on the Gulf of Mexico Shelf, approximately 0.5 million gross acres in the deepwater and approximately 0.2 million gross acres onshore in Texas.  A substantial majority of our daily production is derived from wells we operate offshore.  For more information on W&T Offshore, please visit our website 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 W&T Offshore's Annual Report on Form 10-K for the year ended December 31, 2012 and subsequent Form 10-Q reports found at www.sec.gov or at our website at www.wtoffshore.com under the Investor Relations section.

CONTACT:

Mark Brewer

Danny Gibbons


Investor Relations

SVP & CFO


investorrelations@wtoffshore.com

investorrelations@wtoffshore.com


713-297-8024

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,



2013



2012


2013



2012



(In thousands, except per share data)


























Revenues 


$

244,928



$

237,146


$

984,088



$

874,491
















Operating costs and expenses:















 Lease operating expenses  



75,902




61,910



270,839




232,260

 Gathering, transportation costs and production taxes



6,607




5,404



24,645




20,718

 Depreciation, depletion, amortization and accretion



138,618




104,338



451,529




356,232

 General and administrative expenses 



20,895




19,224



81,874




82,017

 Derivative (gain) loss



2,284




(467)



8,470




13,954

 Total costs and expenses



244,306




190,409



837,357




705,181

 Operating income (loss)



622




46,737



146,731




169,310

Interest expense:















 Incurred



21,484




19,859



85,639




63,268

 Capitalized



(2,521)




(3,375)



(10,058)




(13,274)

Loss on extinguishment of debt



128




-



128




-

Other income



-




5



9,074




215

 Income (loss) before income tax expense (benefit) 



(18,469)




30,258



80,096




119,531

Income tax expense (benefit) 



(6,583)




13,588



28,774




47,547

 Net income (loss) 


$

(11,886)



$

16,670


$

51,322



$

71,984































Basic and diluted earnings (loss) per common share


$

(0.16)



$

0.21


$

0.68



$

0.95
















Weighted average common shares outstanding



75,291




74,470



75,239




74,354
















Consolidated Cash Flow Information















 Net cash provided by operating activities


$

85,525



$

33,648


$

561,358



$

385,137

 Capital expenditures and acquisitions



211,286




372,491



634,378




684,863
















 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)
















Three Months Ended








December 31,





Variance



2013



2012


Variance


Percentage 

Net sales volumes: 













 Oil  (MBbls) 



1,792




1,672



120


7.2%

 NGL (MBbls) 



571




549



22


4.0%

 Oil and NGLs (MBbls)



2,363




2,221



142


6.4%

 Natural gas (MMcf) 



16,771




13,728



3,043


22.2%

 Total oil and natural gas (MBoe)(1)



5,158




4,509



649


14.4%

 Total oil and natural gas (MMcfe)(1)



30,947




27,052



3,895


14.4%














Average daily equivalent sales (MBoe/d) 



56.1




49.0



7.1


14.5%

Average daily equivalent sales (MMcfe/d)  



336.4




294.0



42.4


14.4%














Average realized sales prices: 













 Oil ($/Bbl)


$

94.11



$

100.31


$

(6.20)


-6.2%

 NGLs ($/Bbl)



39.78




36.16



3.62


10.0%

 Oil and NGLs ($/Bbl)



80.98




84.46



(3.48)


-4.1%

 Natural gas ($/Mcf) 



3.15




3.58



(0.43)


-12.0%

 Barrel of oil equivalent ($/Boe) 



47.33




52.51



(5.18)


-9.9%

 Natural gas equivalent ($/Mcfe) 



7.89




8.75



(0.86)


-9.8%














Average per Boe ($/Boe): 













 Lease operating expenses 


$

14.72



$

13.73


$

0.99


7.2%

 Gathering and transportation costs and production taxes



1.28




1.20



0.08


6.7%

 Depreciation, depletion, amortization and accretion



26.88




23.14



3.74


16.2%

 General and administrative expenses 



4.05




4.26



(0.21)


-4.9%

 Net cash provided by operating activities



16.58




7.46



9.12


122.3%

 Adjusted EBITDA



27.10




33.53



(6.43)


-19.2%














Average per Mcfe ($/Mcfe):













 Lease operating expenses 


$

2.45



$

2.29


$

0.16


7.0%

 Gathering and transportation costs and production taxes



0.21




0.20



0.01


5.0%

 Depreciation, depletion, amortization and accretion



4.48




3.86



0.62


16.1%

 General and administrative expenses 



0.68




0.71



(0.03)


-4.2%

 Net cash provided by operating activities



2.76




1.24



1.52


122.6%

 Adjusted EBITDA



4.52




5.59



(1.07)


-19.1%
















(1)

Bcfe and MMBoe are determined using the 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.

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)
















Twelve Months Ended








December 31,





Variance



2013



2012


Variance


Percentage 

Net sales volumes: 













 Oil  (MBbls) 



7,018




6,033



985


16.3%

 NGL (MBbls) 



2,091




2,129



(38)


-1.8%

 Oil and NGLs (MBbls)



9,110




8,163



947


11.6%

 Natural gas (MMcf) 



53,257




53,825



(568)


-1.1%

 Total oil and natural gas (MBoe)(1)



17,986




17,133



853


5.0%

 Total oil and natural gas (MMcfe)(1)



107,915




102,800



5,115


5.0%














Average daily equivalent sales (MBoe/d)  



49.3




46.8



2.5


5.3%

Average daily equivalent sales (MMcfe/d) 



295.7




280.9



14.8


5.3%














Average realized sales prices: 













 Oil ($/Bbl)


$

102.44



$

104.35


$

(1.91)


-1.8%

 NGLs ($/Bbl)



35.07




39.75



(4.68)


-11.8%

 Oil and NGLs ($/Bbl)



86.97




87.50



(0.53)


-0.6%

 Natural gas ($/Mcf)  



3.55




2.94



0.61


20.7%

 Barrel of oil equivalent ($/Boe) 



54.58




50.93



3.65


7.2%

 Natural gas equivalent ($/Mcfe)  



9.10




8.49



0.61


7.2%














Average per Boe ($/Boe): 













 Lease operating expenses 


$

15.06



$

13.56


$

1.50


11.1%

 Gathering and transportation costs and production taxes



1.37




1.21



0.16


13.2%

 Depreciation, depletion, amortization and accretion



25.10




20.79



4.31


20.7%

 General and administrative expenses 



4.55




4.79



(0.24)


-5.0%

 Net cash provided by operating activities



31.21




22.48



8.73


38.8%

 Adjusted EBITDA



33.26




31.65



1.61


5.1%














Average per Mcfe ($/Mcfe): 













 Lease operating expenses 


$

2.51



$

2.26


$

0.25


11.1%

 Gathering and transportation costs and production taxes



0.23




0.20



0.03


15.0%

 Depreciation, depletion, amortization and accretion



4.18




3.47



0.71


20.5%

 General and administrative expenses 



0.76




0.80



(0.04)


-5.0%

 Net cash provided by operating activities



5.20




3.75



1.45


38.7%

 Adjusted EBITDA



5.54




5.28



0.26


4.9%
















(1)

Bcfe and MMBoe are determined using the 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.

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Unaudited)











December 31,



December 31,



2013



2012



(In thousands, except



 share data)

Assets








Current assets:








 Cash and cash equivalents


$

15,800



$

12,245

 Receivables:








    Oil and natural gas sales



96,752




97,733

    Joint interest and other



27,984




56,439

    Income taxes



3,120




47,884

       Total receivables



127,856




202,056

 Prepaid expenses and other assets



29,946




25,822

 Total current assets



173,602




240,123

 Property and equipment – at cost:








 Oil and natural gas properties and equipment (full cost method, of which $116,612 at December 31, 2013 and $123,503 at December 31, 2012 were excluded from amortization)



7,339,097




6,694,510

 Furniture, fixtures and other



21,431




21,786

 Total property and equipment



7,360,528




6,716,296

 Less accumulated depreciation, depletion and amortization



5,084,704




4,655,841

 Net property and equipment



2,275,824




2,060,455

 Restricted deposits for asset retirement obligations



37,421




28,466

 Other assets



20,455




19,943

 Total assets


$

2,507,302



$

2,348,987









Liabilities and Shareholders' Equity








Current liabilities:








 Accounts payable


$

145,212



$

123,885

 Undistributed oil and natural gas proceeds



42,107




37,073

 Asset retirement obligations  



77,785




92,630

 Accrued liabilities



28,000




21,021

 Total current liabilities



293,104




274,609

Long-term debt



1,205,421




1,087,611

Asset retirement obligations, less current portion



276,637




291,423

Deferred income taxes



178,142




145,249

Other liabilities



13,388




8,908

Commitments and contingencies



-




-

Shareholders' equity:








 Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,460,872 issued and 75,591,699 outstanding at December 31, 2013;  78,118,803 issued and 75,249,630 outstanding at December 31, 2012



1




1

 Additional paid-in capital



403,564




396,186

 Retained earnings



161,212




169,167

 Treasury stock, at cost



(24,167)




(24,167)

 Total shareholders' equity



540,610




541,187

 Total liabilities and shareholders' equity


$

2,507,302



$

2,348,987

















 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

 (Unaudited)












Twelve Months Ended




December 31,




2013



2012




(In thousands)






Operating activities:









Net income  


$

51,322



$

71,984


Adjustments to reconcile net income to net cash provided by operating activities:









 Depreciation, depletion, amortization and accretion 



451,529




356,232


 Amortization of debt issuance costs and premium 



1,645




2,575


 Loss on extinguishment of debt 



128




-


 Share-based compensation   



11,525




12,398


 Derivative loss   



8,470




13,954


 Cash payments on derivative settlements (realized)   



(8,589)




(7,664)


 Deferred income taxes   



30,920




88,109


 Asset retirement obligation settlements   



(81,543)




(112,827)


 Changes in operating assets and liabilities 



95,951




(39,624)


 Net cash provided by operating activities 



561,358




385,137











Investing activities:









Acquisitions of property interests in oil and natural gas properties 



(82,424)




(205,550)


Investment in oil and natural gas properties and equipment 



(551,954)




(479,313)


Proceeds from sales of assets and other, net 



21,008




30,453


Purchases of furniture, fixtures and other 



(1,435)




(3,031)


 Net cash used in investing activities 



(614,805)




(657,441)











Financing activities:









Issuance of Senior Notes 



-




318,000


Borrowings of long-term debt 



563,000




732,000


Repayments of long-term debt 



(443,000)




(679,000)


Dividends to shareholders 



(58,846)




(82,832)


Repurchase premium and debt issuance costs



(3,892)




(8,510)


Other



(260)




379


 Net cash provided by financing activities 



57,002




280,037


 Increase in cash and cash equivalents 



3,555




7,733


Cash and cash equivalents, beginning of period 



12,245




4,512


Cash and cash equivalents, end of period 


$

15,800



$

12,245




















 

W&T OFFSHORE, INC. AND SUBSIDIARIES


Non-GAAP 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 "Net Income Excluding Special Items," "EBITDA" and "Adjusted EBITDA."  Adjusted EBITDA margin represents the ratio of Adjusted EBITDA to total revenues.  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. 


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, contract option fee, litigation accruals, loss on extinguishment of debt, depletion expense related to out of period adjustments, and associated tax effects.  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.

 

Adjusted Net Income






















































Three Months Ended



Twelve Months Ended




December 31,



December 31,




2013



2012



2013



2012




(In thousands, except per share amounts)



(Unaudited)


















Net income (loss) 


$

(11,886)



$

16,670



$

51,322



$

71,984


Unrealized commodity derivative (gain) loss 



550




(1,172)




(119)




6,289


Contract option fee 



3




-




(9,062)




-


Litigation accruals 



-




1,250




-




10,250


Loss on extinguishment of debt



128




-




128




-


Depletion expense related to out of period volume adjustments



7,128




-




4,998




-


Income tax adjustment for above items at statutory rate



(2,733)




(27)




1,419




(5,789)


Net income (loss) excluding special items


$

(6,810)



$

16,721



$

48,686



$

82,734



















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


$

(0.09)



$

0.21



$

0.64



$

1.10



















 

Reconciliation of Net Income (Loss) to Adjusted EBITDA


We define EBITDA as net income plus income tax expense, net interest expense, depreciation, depletion, amortization, and accretion. Adjusted EBITDA excludes the unrealized gain or loss related to our derivative contracts, contract option fee, loss on extinguishment of debt, and litigation accruals.  We believe the presentation of EBITDA and Adjusted EBITDA provide useful information regarding our ability to service debt and to fund capital expenditures.  We believe this presentation is relevant and useful because it helps our investors understand our operating performance and makes 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. Adjusted EBITDA margin represents the ratio of Adjusted EBITDA to total revenues.    


The following table presents a reconciliation of our consolidated net income to consolidated EBITDA and Adjusted EBITDA along with our Adjusted EBITDA margin.

 


















Adjusted EBITDA



Three Months Ended



Twelve Months Ended




December 31,


December 31,




2013



2012



2013



2012




(In thousands)



(Unaudited)


















Net income (loss) 


$

(11,886)



$

16,670



$

51,322



$

71,984


Income tax expense (benefit) 



(6,583)




13,588




28,774




47,547


Net interest expense 



18,957




16,479




75,572




49,979


Depreciation, depletion, amortization and accretion



138,618




104,338




451,529




356,232


EBITDA



139,106




151,075




607,197




525,742



















Adjustments:

















Unrealized commodity derivative (gain) loss 



550




(1,172)




(119)




6,289


Contract option fee 



3




-




(9,062)




-


Loss on extinguishment of debt



128




-




128




-


Litigation accruals 



-




1,250




-




10,250


Adjusted EBITDA


$

139,787



$

151,153



$

598,144



$

542,281




































Adjusted EBITDA Margin



57%




64%




61%




62%



















 

SOURCE W&T Offshore, Inc.



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