W&T Offshore Announces 2013 Capital Budget, Drilling Plans & 2013 Guidance And Provides Operations Update
Company announces positive results in its Yellow Rose drilling program

HOUSTON, Feb. 12, 2013 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI)  announced that its Board of Directors has approved a 2013 capital budget of $450 million. The Company also announced production guidance for the first quarter of 2013 in a range of 4.3 MMBoe to 4.8 MMBoe and for the full year of 2013 in a range of 17.0 MMBoe to 18.7 MMBoe.  In addition, the Company provided details about its capital expenditure programs and an operational update, which includes positive results in both its horizontal drilling and 40-acre spacing pilot programs, adding value to its Yellow Rose project.

2013 Capital Budget

Approximately 63% of the $450 million capital budget for 2013 is identified as exploratory drilling to drive organic growth of both reserves and production, with the remaining 37% of the budget directed to oil-focused development activities.  We anticipate allocating 63% of the 2013 budget to projects in the Gulf of Mexico, both on the shelf and in the deepwater, and 37% to projects onshore in Texas. 

Tracy W. Krohn, Chairman and Chief Executive Officer, stated, "In the past few years we have added new exploration projects to support our goal of achieving growth organically through the drill bit, as well as through acquisitions.  In 2013 we are increasing our focus on exploration and building on recent successes.  We have great news with our Yellow Rose project as we are pleased to report positive results in our horizontal drilling program in the Wolfberry; positive results in our 40-acre spacing pilot program; and production from the field is up 100% over last year at this time."

"Our 2013 capital budget of $450 million is designed with a balance of offshore shelf, deepwater and onshore exploration drilling activity to drive organic growth, plus a number of development projects focused on expanding our oil production.  As usual, our budget does not include acquisitions, but we will continue to pursue acquisitions in this very active market to supplement our expected organic growth.  As in the past, we expect to continue to drill within our cash flow."

Offshore Activity

We began 2013 with a high level of activity that was heavily weighted toward exploration projects and currently have four rigs working in the Gulf of Mexico.  We believe our offshore exploration program offers solid opportunities for organic reserve and production growth, as well as builds on our recent successes.

At our highly successful "Mahogany" field, our fifth well in our multi-well drilling program, the Ship Shoal ("SS") 349 A-9 development well was brought on production in mid-January at an initial rate of approximately 2,700 Boe per day from the P-sand, which has traditionally been the field's principal productive reservoir.  The A-9 well exceeded pre-drill expectations in our main target.  Additionally, it discovered another upside reservoir which was also completed and will be retained as a future zone change, increasing total proved reserves for the field.  Current average daily gross production from the Mahogany field is approximately 9,150 Boe (approximately 75% crude oil) which is up from about 1,300 Boe per day gross in late 2011, an increase of approximately 700% over the last 15 months.

On January 15, 2013, we spud the SS 349 A-14 well, the sixth well in our multi-well drilling program at our Mahogany field, which is an exploration well designed to test the T-sand, a deep play located beneath our main reservoir. If successful, it will expand our proved reserves and possibly create additional development opportunities in the field.  The A-14 well also holds proved reserves in the P-sand level, serving as a robust back-up to the exploratory T-sand test.   Following the SS 349 A-14 well, we plan to drill the SS 349 A-15 well which is planned to target multiple stacked amplitudes in the sub-salt section.  The A-15 also has additional field expansion potential in the P-sand and if successful will further expand the P-sand reservoir limits.   We continue to have excellent drilling results to date in this high impact oil field and in the reserve and production expansion potential this field has for the Company.  

In addition, we are currently drilling two exploration wells in the Main Pass ("MP") Area.  One is located in our MP 108 field, being the MP 108 B-1 well targeting the Tex W-6 sand.  We plan to drill another well, the MP 108 B-2 well, immediately following operations on the MP 108 B-1 well.  We recently drilled the MP 159 #1 well to TD but have deemed the well non-commercial.  The well is currently being plugged.

We anticipate drilling at least one additional deepwater exploration well in 2013, and will provide the details for that well in the future.  We expect to have additional capital expenditures in 2013 on our Mississippi Canyon ("MC") 698 "Big Bend" deepwater discovery that reached total depth in late 2012, once it is sanctioned.  Additionally we are currently evaluating the 65 deepwater leasehold blocks we acquired in our Newfield property acquisition in the fourth quarter of last year.  As a result of the high level of interest in those undeveloped leases, we are currently working on several joint venture arrangements.

Our development activity in the Gulf of Mexico includes the MC 243 "Matterhorn" A-2 ST well which is currently drilling in the deepwater and expected to add approximately 1,000 Boe per day production of initial rate.  We expect to follow this well with the planned MC 243 A-5 well, a water injection well that will be used for pressure maintenance in the field. The A-5 well is expected to increase the ultimate recovery of the eastern sector of the field, add reserves and assuming success, would lead to additional secondary reserves expansion in other areas of the field. 

Other development wells on the 2013 schedule include the High Island 21 A-1 well targeting the LH-20 sand which will twin the previously producing High Island 21 A-3 well.  We also expect to finish the tie-back and hook up of the West Cameron 73, a 2012 shelf discovery well with first production expected in the third quarter of 2013.

The details of these offshore wells are outlined in the table below.

Wells Completed in the Fourth Quarter 2012



Block/Well

WI%


Type

Location

Target

Net Cost

Comments











WC 73 #2

30


EXP

Shelf

Gas and condensate in Cris R section at ~18,100'  

~$13.2 MM

Completed, awaiting facilities installation. Est. 1st production - Q3 2013.  Est IP: ~380 Boepd net



















Drilling Activity in the Fourth Quarter 2012



Block/Well

WI%


Type

Location

Target

Net Est. Cost

Comments











SS 349 A-9
(Mahogany) 

100


DEV

Shelf

Oil in P sand at ~14,300' 

~$27.2 MM

Completed Jan 3, discovered 2nd pay zone adding to proved reserves. 1st production - Jan 2013.  IP rate: ~2,700 Boepd


MC 698 #1
(Big Bend)

20


EXP

Deepwater

Oil at ~15,300' (Big Hum) sand

~$20.2 MM

Reached TD, logged ~150 ft oil pay in two high quality Miocene sands. Development pending.  


MP 163 #1

40


EXP

Shelf

Gas and liquids at ~8,650'

~$2.9 MM

Reached TD in mid-Oct, deemed non-commercial, subsequently plugged.



















Current Drilling Activity in the First Quarter 2013



Block/Well

WI%


Type

Location

Target

Net Est. Cost

Comments











MP 108 B-1

100


EXP

Shelf

Gas and liquids in Tex W 6 sand at ~14,000' TVD

~$24.5 MM

Drilling ahead.  Est. 1st production - Q2 2013.  Target IP: ~1,200 Boepd.  Unrisked anticipated recovery: ~ 1.8 MMBoe.


MC 243 A-2 ST
(Matterhorn)

100


DEV

Deepwater

Proved oil reserves in the A sand at ~6,800' TVD

~$23.8 MM

Rig on location preparing to side-track at ~5,100'.  Est. 1st production - late Q1 2013.  Target IP: ~1,000 Boepd.


SS 349 A-14
(Mahogany)

100


EXP

Shelf

Oil at ~17,200' TVD in the T2 sand (exploration target).  Secondary target in the P sand (development) at ~14,200' TVD

~$39 MM

Drilling ahead. Est. 1st production - late Q2 2013.  Est. IP rate: ~2,000 Boepd.  Unrisked anticipated recovery: ~ 3.1 MMBoe.


MP 159 #1

100


EXP

Shelf

Gas and liquids ~7,400' in the UVIG-3 sand

~$6.6 MM

Drilling rig on location. Deemed
non-commercial, currently being plugged.



















Upcoming Drilling Activity in 2013



Block/Well

WI%


Type

Location

Target

Net Est. Cost

Comments











MP 108 B-2

100


EXP

Shelf

Gas and liquids in Tex W 6 sand at ~14,000' TVD

~$24.1 MM

Projected spud date - Q2 2013, Est 1st production - Q3 2013, Target IP: ~1,200 Boepd. Unrisked anticipated recovery ~ 1.7 MMboe


MC 243 A-5
(Matterhorn)

100


DEV

Deepwater

Water injection well for increased reserves (oil)

~$28.6 MM

Projected spud date - Q2 2013. Est. project online - Q3 2013.


SS 349 A-15
(Mahogany)

100


EXP

Shelf

Multiple exploratory targets (N, O, P, Q, Q5 sands) ~ 14,000'-14,500' TVD

~$35 MM

Projected spud date - mid 2013.  Est. 2st production - Q4 2013. Target IP: ~1,500 Boepd.  Unrisked anticipated recovery ~ 4 MMBoe. 


HI 21 A-1

100


DEV

Shelf

LH20 sands;  low risk gas development extension @ ~ 12,500'

~$25 MM

Projected spud date Q1 '13.  Est. 1st production: Q3 2013. Target IP: ~1,500 Boepd.  Unrisked anticipated recovery:  ~ 3.2 MMBoe. 

Onshore Operations Update:

Onshore, as a result of our success with both the Wolfcamp horizontal drilling program and the 40-acre infill spacing, we have added value to our Yellow Rose project in the Permian Basin (Martin, Dawson, Gaines and Andrews counties).  Our 2013 budget provides for the drilling of seven horizontal and 20 vertical wells and we currently have two rigs running in the field.

During the fourth quarter of 2012, we completed 18 new wells at our Yellow Rose project, bringing the total completed wells for 2012 to 64 wells.  During 2012, W&T focused on three specific areas to add value to our Yellow Rose Wolfberry development, which were:  (1) enhanced 80 acre vertical development drilling program, (2) down-spaced pilot program to 40 acre spacing vertical development, and (3) exploring our horizontal development potential in the Wolfcamp.  Tactically we have focused on field optimization, as well as on continuous and aggressive stimulation development and deployment in our vertical and horizontal campaigns.  Current production rate for our Yellow Rose project is approximately 5,150 Boe per day gross which is 100% above field production rates a year ago.  This production performance improvement is driven by several factors including attractive vertical well completion performance, continued improvements in our field uptime and effectiveness, attractive results from our 40-acre infill program and, most recently, encouraging results from our new Wolfcamp horizontal wells. 

Our more recent vertical wells have seen improved initial production rates with our latest wells averaging approximately 67 Boe per day (average 30 day production rate) as we continue to refine our fracture stimulation program, with vertical well costs averaging approximately $ 2.3 million.  Prior to year end 2012, the company carried no "proved" reserves associated with down-spaced 40 acre locations.  A portion of our 2012 drilling capital was aimed at infill drilling specific pilot areas to 40 acre vertical well spacing and we had good success with the down-spacing program, observing positive incremental production and incremental reserves in our 40 acre pilot areas.  At year end, we began booking a portion of our 40 acre infill locations into "proved" and expect that trend to continue into 2013, 2014 and beyond.  Should we be able to fully develop our acreage on 40 acre locations, the company would possess a total of 200 to 300 40-acre locations across our Yellow Rose project. 

Complementing our vertical development, during 2012 we drilled and brought on line two new horizontal Wolfcamp wells, with one well achieving an initial production ("IP") rate of 485 Boe per day and another well achieving 346 Boe per day.  W&T's longest Wolfcamp horizontal has been a 7,482' lateral with a 23 stage frac treatment.  Our most recent horizontal well, currently on flowback, has just been stimulated with a 28 stage frac treatment.  We are pleased with our initial horizontal well results and our leading completion practices in this emerging play.  As a result of our successful horizontal exploration tests of the Wolfcamp formation, we have budgeted to drill and complete seven horizontal Wolfcamp wells for 2013.  These wells are designed to have an average lateral length of 5,400 feet completed with between 20 and 22 hydraulic fracturing stages at a total well cost of approximately $ 6.0 million to $7.0 million, depending on the length of the lateral.  Based on our early evaluation of the program, we expect IP rates of 350 to 400 Boe per day and estimated ultimate recoveries ("EUR") of 300 to 450 MBoe, also depending on the length of the lateral.  Assuming continued success with this program, we anticipate expanding our horizontal operations in the Wolfcamp formation and potentially testing additional horizontal levels (benches) in other formations on our acreage position.  Ultimately, we may consider further vertical well down spacing to 20-acre spacing or even less, adding even greater development potential for our acreage position.

In Terry County, West Texas, our horizontal drilling program is progressing with two wells fracture stimulated and on flowback. To date, we do not have enough information on the flowbacks to determine our future development plans.  We anticipate having more information within the next few months.

In East Texas at our Star Prospect, we have completed drilling and fracture stimulation of the third and fourth wells of our initial delineation program.  Both of those wells are now on flowback, and we should be able to determine our future plans on this project in the near term. 

The details of our onshore wells are outlined in the table below.

Wells Completed in Fourth Quarter 2012



Project & Area

WI%

 Type

# of Wells


Target 

Net Cost

Comments

Permian Basin

















Yellow Rose
Pinotage 8H 

100

EXP

1


Horizontal Wolfcamp  

~$5.1 MM

Currently producing
IP rate: 485 Boepd (gross)
30 Day Avg: 309 Boepd (gross)


Yellow Rose 

90

EXP

1


4,500' vertical section in the Wolfberry

~$2.0 MM

Drilled on 40 acre spacing, on production 


Yellow Rose 

100

DEV

16


4,500' vertical section in the Wolfberry

~$2 MM per well

Drilled on 80 acre spacing, on production


Terry County
State Travis Henson #1H

90

EXP

1


Horizontal Wolfcamp  

~$6.6 MM

Completed, on flowback


Terry County
Holmes 23-4 #1H

90

EXP

1


Horizontal Wolfcamp  

~$5.9 MM

Completed, on flowback









East Texas

















Star Prospect
Colwell A8 #1H

97

EXP

1


James Lime Horizontal

~$7.3 MM

3rd well of 4 well delineation program - on flowback


Star Prospect
McMahon A-28 #1H

97

EXP

1


James Lime Horizontal

~$7.6 MM

4th well of 4 well delineation program - on flowback



















Drilling Activity in the Fourth Quarter 2012



Project & Area

WI%

 Type

# of Wells


Target 

Net Est. Cost

Comments

Permian Basin

















Yellow Rose 

100

DEV

12


4,500' vertical section in the Wolfberry

~$2.3 MM per well

Reached TD, 10 awaiting completion, 2 on flowback


Yellow Rose
Chablis #5H

100

EXP

1


Horizontal Wolfcamp  

~$7.4 MM

Recently completed and currently producing
IP rate: 346 Boepd (gross)
30 Day Avg: N/A  too early


Yellow Rose
UL 6-23 Unit 2H

100

EXP

1


Horizontal Wolfcamp  

~$6.8 MM

28 Stage Frac treatment in Feb.;  Well on flowback



















Current Drilling Activity in the First Quarter 2013



Project & Area

WI%

 Type

# of Wells


Target 

Net Est. Cost

Comments

Permian Basin

















Yellow Rose 

100

DEV

2


4,500' vertical section in the Wolfberry

~$2.3 MM per well

Drilling, single vertical rig program



















Upcoming Drilling Activity in 2013



Project & Area

WI%

 Type

# of Wells


Target 

Net Est. Cost

Comments

Permian Basin









Yellow Rose 

100

DEV

~20 


4,500' vertical section in the Wolfberry

~$2.3 MM per well

Single rig program underway for vertical wells.  


Yellow Rose 

100

EXP

~7 


Horizontal Wolfcamp  

~$6.0 MM to $7.0 MM

Single rig program underway for horizontal wells.  











Yellow Rose Horizontal Wells - Avg days to drill: 39 days, Days to 1st production: 90 days, Est. Gross EUR: ~300-450 Mboe (oil plus wet gas, no NGLs), Est. IP: 350-400 Boepd gross











Yellow Rose Vertical Wells - Avg days to drill: 18 days, Days to 1st production: 60 days, Est. Gross EUR: ~119 Mboe (oil plus wet gas, no NGLs), Est. IP:  ~ 67 Bopd gross










2013 Outlook

Our guidance for the first quarter and full year 2013 is provided in the table below and represents the Company's best estimate of the range of likely future results.  Our results may be affected by the factors described below in "Forward-Looking Statements."  Our expected results for the full year 2012 are unchanged from our prior guidance last provided on November 28, 2012.

  Estimated Production

First Quarter

2013

 Full-Year

2013

Oil and NGLs (MMBbls)

2.0 – 2.2

8.1 – 9.0

Natural gas (Bcf)

14.2 – 15.7

52.9 – 58.5

Total (Bcfe)

26.0 – 28.7

102.0 – 112.0

Total (MMBoe)

4.3 – 4.8

17.0 – 18.7

Operating Expenses
        
($ in millions)

First Quarter

2013

Full-Year

2013

Lease operating expenses

$55.7 – $61.5

$221 – $244

Gathering, transportation &    production taxes

$7.7 – $8.5

$37 – $41

General and administrative

$22.3 – $24.7

$78 – $86

Income tax rate (1)

36%

36%


(1) For income statement purposes only and not a reflection of estimated tax payments or refunds in 2013.

Derivative Schedule Update:

W&T has posted an update to its commodity derivatives schedule provided in the investor relations section of its website that includes all of our most recent changes to our derivatives positions.  Investors may also visit the website to sign up to receive alerts of updates to our commodity derivative positions schedule.

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 72 offshore fields in federal and state waters (69 producing and three fields capable of producing).  W&T currently has over 1.4 million gross acres under lease including over 710,000 gross acres on the Gulf of Mexico Shelf, over 480,000 gross acres in the deepwater and over 221,000 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, 2011 and subsequent Form 10-Q reports found at www.sec.gov or at our website at www.wtoffshore.com under the Investor Relations section.

We may use the terms "potential reserves," "targeted reserves," "unrisked anticipated recovery", "ultimate recovery" and "EUR" to describe estimates of potentially recoverable hydrocarbons that the SEC rules strictly prohibit us from including filings with the SEC. These are the Company's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute "reserves" within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System or SEC rules and do not include any proved reserves. EUR estimates and drilling locations have not been risked by Company management except where indicated. Actual locations drilled, and quantities that may be ultimately recovered from the Company's interests could differ substantially from the Company's estimates. There is no commitment by the Company to drill all of the drilling locations which have been attributed to these quantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of targeted reserves, potential reserves and average well EUR may change significantly as development of the Company's oil and gas assets provide additional data.

Our production forecasts, estimated initial production rates and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

CONTACT:

Mark Brewer 

Danny Gibbons


Investor Relations

SVP & CFO


investorrelations@wtoffshore.com 

investorrelations@wtoffshore.com


713-297-8024 

713-624-7326

 

SOURCE W&T Offshore, Inc.

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