W&T Offshore Reports Second Quarter 2013 Financial and Operational Results

HOUSTON, Aug. 7, 2013 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today announced financial and operational results for the second quarter of 2013.  Some of the highlights include:  

  • Production volumes averaged 45.3 MBoe per day, or 271.8 MMcfe per day during the second quarter of 2013.  Approximately 3.2 Bcfe of production was deferred due to operational issues during the quarter.  We estimate that we are currently capable of producing approximately 330 MMcfe per day when these operational issues are resolved.
  • Oil production for the second quarter of 2013 increased 14.2% over the second quarter of 2012. Production volumes were split 40% oil, 12% NGLs and 48% natural gas. 
  • Average realized sales price was $101.78 per barrel for oil, $32.17 per barrel for NGLs and $4.22 per Mcf for natural gas.
  • After the quarter end, we brought on line the Ship Shoal 349 "Mahogany" A-14 well, which has reached a peak rate so far of 3,588 barrels of oil per day and 6.3 MMcf of gas per day, for a total of approximately 4,644 Boe per day gross (3,870 Boe per day net to W&T after royalties).
  • Revenues were $235.4 million, net income was $22.4 million and earnings per share were $0.29.
  • Adjusted EBITDA was $142.8 million, up $8.0 million over the second quarter of last year, and Adjusted EBITDA Margin was 61%. 
  • Net cash provided by operating activities for the first half of 2013 was $297.4 million, up from $241.3 million for the comparable 2012 period. 
  • Completed one offshore well during the quarter and, as of June 30th, four additional offshore wells were actively drilling or in completion phase.
  • Completed nine onshore wells in the Permian Basin of West Texas (two horizontal and seven vertical) during the quarter and two additional wells (one horizontal and one vertical) during July.
  • In June, we announced our participation in a new deepwater prospect, "Troubadour", in Mississippi Canyon 699, which is currently drilling in the block adjacent to our 2012 discovery, MC 698 "Big Bend".
  • Paid a dividend of $0.09 per share during the quarter.
  • On August 1, 2013, we received tax refunds totaling approximately $54 million.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "2013 is developing into another successful year with the drill bit for W&T, which includes multiple discovery wells that are expected to add substantial new reserves and further our efforts for organic growth.  Year to date, we have drilled six successful wells offshore in the Gulf of Mexico and have additional exploratory wells underway. Our Mahogany field is expanding with each exploratory well, as we continue to add high quality oil sands which have not previously been discovered.  We will continue to explore within this field as the reservoir limits have not yet been determined.

"In addition to our other recent discoveries, we are participating in the drilling of another deepwater exploration well at 'Troubadour', being Mississippi Canyon 699, located in the deepwater adjacent to our successful discovery 'Big Bend' at Mississippi Canyon 698.  Assuming success, Troubadour would most likely be co-developed with Big Bend, adding considerable future production and reserves.

"Onshore in West Texas at our Yellow Rose field we continue to increase our initial production (IP) rates and expand the estimated ultimate recoveries (EURs) in our vertical wells.  Our average daily production is up nearly 15% since the fourth quarter of 2012.  We recently added 2,160 net acres to our Yellow Rose position, bringing our total net acreage to 25,730 acres.  This new acreage provides us with even more opportunities for production and reserve growth."

Revenues, Production, and Price:  Revenues for the second quarter were $235.4 million compared to $215.5 million in the second quarter of 2012.  Overall, revenues increased due to a 16.8% rise in average commodity prices, which was slightly offset by a 6.8% decrease in total production for the second quarter.  During the second quarter of 2013, we sold 1.7 million barrels of oil, 0.5 million barrels of natural gas liquids (NGLs) and 11.8 billion cubic feet (Bcf) of natural gas as compared to 1.5 million barrels of oil, 0.6 million barrels of NGLs and 14.3 Bcf of natural gas for the same period of 2012.  In total, we sold 4.1 million barrels of oil equivalent (Boe) at an average realized sales price of $56.88 per Boe compared to 4.4 million Boe sold at an average realized sales price of $48.71 per Boe in the second quarter of 2012.  Oil revenues were higher due to a 14.2% increase in sales volumes, which was partially offset by a slight decrease in prices.  NGL revenue declined due to lower prices and lower sales volumes. Natural gas revenues were higher due to a 69.5% increase in prices, which were partially offset by a 17.3% decrease is sales volumes.  

Production for the second quarter of 2013 was affected throughout the quarter by downtime at up to 10 different fields and or platforms for a number of reasons including third party pipeline outages and platform maintenance, as well as certain well performance issues.  We estimate we have had between 30 MMcfe/day and 90 MMcfe/day of our production shut in during portions of April, May and June as a result of these issues, which include the following: production at Mississippi Canyon 506 "Wrigley" continues to be deferred as a result of maintenance at Shell's Cognac platform and related pipelines; production was shut in at our East Cameron 321 platform for water treating upgrades and oil and gas pipeline issues, and two wells in our Fairway field are shut in awaiting workovers; and third party oil sales pipelines were shut in at Mississippi Canyon 800 "Gladden" and Ship Shoal 349 "Mahogany" at various times during the quarter.  Total deferred production for the second quarter was approximately 3.2 Bcfe.

Adding back our volumes related to downtime, production for the quarter would have averaged roughly 307.8 MMcfe per day.  From a commodity standpoint, roughly 70% of the deferred volumes during the second quarter were gas related.  This operationally deferred production is now reflected in our revised production guidance provided later in this news release.  Our guidance also reflects 2.5 Bcfe of potential downtime for tropical storms, but does not account for any volumes related to potential acquisitions or divestitures.  The current realized net production rate for early August is approximately 295 Mcfe per day, with a total company production capacity in excess of 330 Mcfe per day (including temporary shut in production expected to resume in the short term).

Net Income & EPS:  Second quarter of 2013 net income was $22.4 million, or $0.29 per common share, compared to net income of $53.6 million, or $0.70 per common share for the same period in 2012.  Net income for the second quarter of 2013, adjusted to exclude special items, was $15.3 million, or $0.20 per common share.  This compares to $21.0 million, or $0.28 per common share for the second quarter of 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 news release for a description of the special items. 

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 back of this news release.  Adjusted EBITDA for the second quarter of 2013 was $142.8 million, up from $134.9 million for the same period in 2012, due to higher oil production volumes and higher natural gas prices.    Net cash provided by operating activities for the first half of 2013 was $297.4 million, compared to $241.3 million for the same period of the prior year.  In August 2013, we received tax refunds totaling approximately $54 million from the U.S. Treasury in connection with federal net operating loss carrybacks to 2010 and 2011.    

As of June 30, 2013, we have spent $44.5 million and expect to incur an additional $2.6 million for removal of wreckage associated with platforms damaged by Hurricane Ike.  In connection with our litigation with our excess insurance underwriters, on July 31, 2013, the Court ruled in favor of the underwriters, adopting their position that the excess policies cover removal of wreck and debris claims only to the extent the limits of our Energy Package policies have been exhausted with removal of wreck and debris claims.  We disagree with the Court's ruling and intend to appeal the decision. 

Lease Operating Expenses (LOE):  Lease operating expenses, which include base lease operating expenses, insurance premiums, workovers and maintenance on our facilities, increased $8.0 million to $68.2 million in the second quarter of 2013 compared to the second quarter of 2012.  On a component basis, all costs were lower except workover expense which increased $11.4 million primarily as a result of a rig workover on a well at our Main Pass 69 field, which we expect to return to production during the fourth quarter of this year. 

Depreciation, Depletion, Amortization, and Accretion (DD&A): DD&A, including accretion for ARO, increased to $4.04 per Mcfe for the second quarter of 2013 from $3.24 per Mcfe in the prior year period.  On a nominal basis, DD&A increased to $99.9 million for the second quarter of 2013 from $85.9 million in the prior-year period.  DD&A on a per Mcfe basis and nominal basis increased primarily due to costs capitalized to the full cost pool from both the unevaluated pool and from increases in our ARO estimates without a corresponding increase in proved reserves, which primarily occurred in the latter part of 2012.  In addition, we incurred development costs during 2012 and the first half of 2013 above previous estimates, and as a result, we increased our estimates of future development costs.  The Newfield properties acquired in 2012 also increased the DD&A rate on a per Mcfe basis.

General and Administrative Expenses (G&A):  G&A increased to $19.9 million for the second quarter of 2013 from $14.6 million for the prior-year period primarily due to increases in accrued goal-based incentive compensation, timing of surety premiums associated with supplemental bonding, consulting services related to drilling operations, and lower overhead billed to joint interest partners.  The second quarter of 2012 reflected no accrual for cash-based incentive compensation.

Derivatives:  For the second quarter of 2013 and 2012, our derivative net gains were $12.8 million and $49.9 million, respectively, and relate to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices.  Although the contracts relate to production for the current year and next year, changes in the fair value for all open contracts are recorded currently.  For the second quarter of 2013, the net gain was composed of a $1.9 million realized and a $10.9 million unrealized gain.  For the second quarter of 2012, the net gain consisted of a realized loss of $0.3 million and an unrealized gain of $50.2 million.  We have posted an update to our commodity derivatives schedule in the investor relations section of our website at http://www.wtoffshore.com

Interest Expense:  Interest expense incurred increased to $21.5 million for the second quarter of 2013 from $14.7 million for the prior-year period.  The aggregate principal amount of our 8.50% Senior Notes outstanding was $900.0 million in the second quarter of 2013, compared to $600.0 million in the prior-year period due to the issuance of 8.50% Senior Notes during October 2012.  During the second quarter of 2013 and 2012, $2.5 million and $3.3 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties.  The decrease is primarily attributable to reclassifying various unevaluated properties to the full cost pool during the fourth quarter of 2012.

Income Taxes: Income tax expense declined to $12.4 million for the second quarter of 2013, compared to $34.2 million for the same period of 2012, primarily due to lower pre-tax income.  Our effective tax rate for the three months ended June 30, 2013 was 35.7% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes.  Our effective tax rate for the second quarter of 2012 was 38.9% and differed from the federal statutory rate primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a result of loss carrybacks to prior years. 

Capital Expenditures:  Our capital expenditures for the first six months of 2013 were $299.2 million.  Capital expenditures were composed of $109.3 million for exploration activities, $168.1 million for development activities, and $21.8 million for leasehold and other costs.  Offshore activities accounted for 64% of the capital expenditures with 36% allocated to onshore activities.

Operations Review and Update 

OFFSHORE 

Offshore Wells Completed in the Second Quarter 2013



Block/Well

WI%


Type

Location

Target


Comments











MC 243 A-2 ST
(Matterhorn)

100


DEV

Deepwater

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


Currently producing.  



















Current Offshore Drilling Activity in the Third Quarter 2013



Block/Well

WI%


Type

Location

Target


Comments











SS 349 A-14
(Mahogany)

100


EXPL

Shelf

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


Currently producing.











MP 108 B-1

100


EXPL

Shelf

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


Well is completed and awaiting final hook-up. 











MC 243 A-5
(Matterhorn)

100


EXPL

Deepwater

Water injection well for increased reserves (oil)


Well has reached TD and is currently awaiting completion.











HI 21 A-1
(High Island 22 field)

100


DEV

Shelf

Gas and liquids at ~12,500' in the LH-20 sand


Well has reached TD and is currently being completed.











MC 699
(Troubadour)

20


EXPL

Deepwater

Exploration prospect in the block adjacent to MC 698 "Big Bend" discovery 


Currently drilling.  Well projected to reach TD within the week.



















Upcoming Offshore Drilling Activity in 2013



Block/Well

WI%


Type

Location

Target


Comments











SS 349 A-15
(Mahogany)

100


EXPL

Shelf

Multiple exploratory oil targets (N, O, P, Q, Q5 sands) at 13,000' to 15,500' TVD


Projected spud date - Q3 2013.  











EC 321 A-2 ST

100


EXPL

Shelf

Targeting new oil reserves in the Lentic 1 sand at ~8,500 ' TVD


Projected spud date - Q3 2013.










OFFSHORE EXPLORATION AND DEVELOPMENT

Deepwater Gulf of Mexico
Capitalizing on the late 2012 discovery at Mississippi Canyon 698, Big Bend, we have acquired a 20% working interest in the Noble-operated Troubadour well in Mississippi Canyon 699.  Drilling operations are currently underway at Troubadour, and we expect the well to reach total depth (TD) in the next few days.  Assuming success, we would expect that Troubadour would be co-developed with Big Bend, adding production and reserves.

Ship Shoal 349 "Mahogany" Field
During July we made a deep shelf subsalt discovery in the T-sand in our Ship Shoal 349 Mahogany field.  The SS 359 A-14 well exceeded our pre-drill expectations reaching a peak production rate from the T-Sand (in excess of 17,200' total vertical depth) of 3,588 barrels of oil per day and 6.3 MMcf of gas per day, for a total of approximately 4,644 Boe per day gross (3,870 Boe per day net to W&T after royalties).  The T-Sand is the deepest sand discovered in this field, as there is additional pay identified in the M-Sand, N-Sand, and O-Sand, all of which represent future reserve additions to the Company.  The well also penetrated a thicker-than-expected P-sand interval (the main field pay sand) which will also serve as a future recompletion.  In total, the A-14 well logged over 370 feet of net oil pay, with the T-Sand accounting for 108 feet of the total net pay.  This new discovery is expected to stimulate additional drilling in 2014 to exploit all of these oil sands encountered in the A-14 well.

The platform rig at Mahogany is currently working on a major recompletion in the A-4 well, designed to bring a behind pipe P-Sand interval into production at an expected rate of 1,000 Boe per day net to W&T after royalties with an anticipated production date of August or September.  Following the A-4 recompletion we expect to spud the A-15, a deep shelf subsalt exploratory well, which targets oil sands in multiple horizons.  The A-15 well is scheduled to reach TD near the end of 2013 or early 2014 with a target IP rate of 1,390 Boe per day net to W&T after royalties.  The target reserve potential associated with the A-15 well is anticipated to be in the range of 1.8 to 6.2 million Boe. 

Our sub-salt Mahogany oil field continues to expand in both the aerial footprint as well as in vertical column and number of productive sand intervals.  With the Mahogany field's existing infrastructure, our new extension reserve additions are particularly impactful from a value perspective with our ability to rapidly bring new production on stream and quickly monetize new reserves.

Main Pass 108 Field
At our Main Pass 108 field, we recently completed the B-1 ST well which is in the final stages of pre-production hookup.  The well encountered our objective sand, the Tex W-6 (73' of measured depth net pay), and logged additional pay (30' of measured depth net pay) in the Tex W-3 sand.  Initial production is expected in August at a rate of 950 Boepd net. The well will result in new reserve bookings in both the Tex W-6 primary zone as well as the secondary sand, the Tex W-3.

Mississippi Canyon 243 "Matterhorn" Field
During the second quarter we began producing the Mississippi Canyon 243 A-2 side track and commenced operations on the A-5 well to drill a side track for a pressure maintenance project.  We recently reached TD, and logged approximately 220 feet of net pay in the well exceeding pre-drill expectations with one of the thickest A-sand intervals in the field.  We currently plan to produce the A-5 for a period of time before conversion to water injection for field pressure maintenance.  We plan to commence completion operations in September with anticipated first production early in the fourth quarter of 2013.

High Island 22 Field
In early July we reached TD at our High Island 21 A-1 development well.  The well encountered the main pay sands largely as expected and in addition has penetrated additional upside pay zones above the main pay that will serve as future recompletion intervals.   One of these zones, the LH16 will also result in additional reserve bookings.  Completion operations are currently underway, with first production expected in either the late third quarter or early fourth quarter of 2013.  The target initial production rate is approximately 1,500 Boe per day net to W&T after royalties.

East Cameron 321 Field
We will mobilize a rig in September to our East Cameron 321 platform to begin drilling the A-2 ST exploratory well.  Our current project timeline has the well coming online with initial production in October 2013.  The target initial production rate is approximately 850 Boe per day net to W&T after royalties.  EC 321 has been a historically significant oil producing field, and this project has a target reserve potential of 1.1 MMBoe.

ONSHORE  


Onshore Wells Completed in Second Quarter 2013



Project & Area

WI%

 Type

# of Wells


Target 


Comments

Permian Basin

















Yellow Rose
Horizontal

100

DEV

2


Horizontal Wolfcamp "A"  


1 well on flowback, 1 well on production











Yellow Rose
80 Acre Verticals

100

DEV

6


4,500' vertical section in the Wolfberry


Wells on production











Yellow Rose
40 Acre Verticals

100

EXP

1


4,500' vertical section in the Wolfberry


Well on production



















Onshore Wells Completed in the Third Quarter 2013



Project & Area

WI%

 Type

# of Wells


Target 


Comments

Permian Basin

















Yellow Rose
Horizontal

100

DEV

1


Horizontal Wolfcamp "A" 


Well on production











Yellow Rose
80 Acre Verticals

100

DEV

1


4,500' vertical section in the Wolfberry


Well on production











Yellow Rose Horizontal Wells - Targeted "all-in" well cost: $6 - $7 million, Avg days to drill: 39 days, Days to 1st production: 90 days, Targeted gross expected ultimate recovery ("EUR"): ~300-450 Mboe, Targeted initial production ("IP"): 350-400 Boepd gross (EURs and IP rates are oil plus wet gas, does not include NGL uptick), and all other costs attributable to well to achieve first production.











Yellow Rose Vertical Wells - Targeted "all-in" well cost: $2.0 - $2.3 million, Avg days to drill: 18 days, Days to 1st production: 60 days, Targeted gross EUR: ~130 Mboe, Targeted IP: 100 Boepd gross (EURs and IP rates are oil plus wet gas, does not include NGL uptick), and all other costs attributable to well to achieve first production.

 

ONSHORE EXPLORATION AND DEVELOPMENT

Yellow Rose Project
We are continuing our current two-rig drilling program at Yellow Rose and have completed nine wells (two horizontal wells and seven vertical wells) during the second quarter.  We completed two additional wells, one horizontal and one vertical, during July.  The June exit rate at Yellow Rose was approximately 3,989 net Boe per day.  During July, the field hit a new peak production high of 4,387 net Boe per day.  The field has continued to see increases in the average 30-day peak production rate as more high-quality vertical wells are brought online.  We have continued to drill additional wells on 40-acre spacing during the quarter and our current results are consistent with the type curves seen in the offset 80-acre wells on our Yellow Rose acreage adding additional momentum for our down-spacing infill program.  We have booked reserves for approximately fifty PUD locations on 40-acre spacing, which represents only a small percentage of our total potential 40-acre down-spacing well locations.  Further upside for the company exists when we move towards 20 acre vertical spacing tests which will be a consideration for 2014 capital.  

Having completed six horizontal wells in the Yellow Rose area, we are in the early stages of our horizontal well program.  We continue to refine target depths, optimize our specific completion techniques and lateral lengths, and evaluate early time production trends in all our wells.  We have had varying results in our horizontal program with current efforts limited to the Wolfcamp A formation.  During the third quarter of 2013, we plan to spud our first Wolfcamp B horizontal well.  Early indications and petrophysical analysis suggest equivalent production potential from this interval compared to other known Wolfcamp B production elsewhere in the basin and we look forward to testing this new formation with preliminary Wolfcamp B results expected before year end 2013.  Additionally, the company is aggressively evaluating other zones equally attractive for potential horizontal exploitation, such as the Spraberry, additional Wolfcamp members, the Cline and other zones. 

During the second quarter, W&T acquired an additional 2,160 net acres of undeveloped acreage directly offsetting and surrounded by our existing Yellow Rose field infrastructure and production, increasing our net acreage position by approximately 10%.  The acquired acreage offers us an excellent platform for growth, continued production expansion, and excellent operational and cost synergies with our existing core field area.  We anticipate additional reserve bookings during 2013 as a result of this new acreage purchase.

Star Project 
We are continuing to monitor our four initial wells that were drilled on our East Texas acreage and have begun planning our fifth horizontal well.  We expect to commence drilling the fifth well during the fourth quarter of 2013.

Recompletions and Workovers
During the second quarter, we had three offshore recompletions and eight onshore recompletions for a total cost of $3.3 million.  The total impact was a net initial production gain of 775 Boe per day.  Workovers for the quarter totaled $17.2 million and resulted in a net initial production increase of 2,195 Boe per day.  The total cost of workovers for the quarter was abnormally high due to the inclusion of the Main Pass 69 E-1 well; a rig-based workover to replace the subsurface safety valve which will allow for incremental production later this year.

Outlook 
Our guidance for the third quarter and full year 2013 is provided in the table below and represents our best estimate of the range of likely future results.  Our guidance includes an estimated 2.5 Bcfe of potential tropical storm downtime in the third quarter.  These guidance numbers do not reflect the impact of either potential acquisitions or divestitures.  Our results may be affected by the factors described below in "Forward-Looking Statements."

Estimated Production

Third Quarter

2013

Previous

Full-Year

2013

Revised

Full-Year

2013

Oil and NGLs (MMBbls)

2.0 – 2.3

8.1 – 9.0

9.0 – 9.5

Natural Gas (Bcf)

10.1 – 11.5

52.9 – 58.5

47.4 – 49.5

Total (Bcfe)

22.2 – 25.2

102.0 – 112.0

101.3 – 106.5

Total (MMBoe)

3.7 – 4.2

17.0 – 18.7

16.9 – 17.7





Operating Expenses

($ in millions)

Third Quarter

2013

Previous

Full-Year

2013

Revised

Full-Year

2013

Lease operating expenses

$68 - $77

$221 - $244

$249 – $275

Gathering, transportation, & production taxes

$7 - $8

$37 - $41

$26 – $31

General & administrative

$21 - $24

$78 - $86

$78 – $86

Income tax rate (1)

36%

36%

36%


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

Conference Call Information:  We will hold a conference call to discuss these financial and operational results on Thursday, August 8, at 10:00 a.m. Eastern Time.  To participate, dial (480) 629-9835 a few minutes before the call begins.  The call will also be broadcast live over the Internet from our website at www.wtoffshore.com.  A replay will be available until August 15 and may be accessed by calling (303) 590-3030 and using the pass code 4628422#.

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 71 offshore fields in federal and state waters (65 producing and six fields capable of producing).  W&T currently has under lease over 1.4 million gross acres including over 710,000 gross acres on the Gulf of Mexico Shelf, over 480,000 gross acres in the deepwater and over 220,000 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, 2012 and on Form 10-Q for the quarter ended March 31, 2013 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 in filings with the SEC. These are our 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 unless the well was included in previously disclosed proved undeveloped reserve estimates. 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 our interests could differ substantially from our estimates and targets. We make no commitment to drill all of the drilling locations which have been attributed these quantities and our drilling plans are subject to revision. Factors affecting ultimate recovery and reserve estimates and targets include actual drilling results, including geological and mechanical factors affecting recovery rates, which will vary from well to well; and 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.. Estimates of targeted reserves, potential reserves and average well EUR may change significantly as development of our oil and gas assets provide additional data.

Our production forecasts, estimated and targeted initial production rates and expectations for future periods are similarly 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. Actual production will vary from well to well.  

W&T OFFSHORE, INC. AND SUBSIDIARIES 

Condensed Consolidated Statements of Income (Loss)

(Unaudited)


















Three Months Ended


Six Months Ended



June 30,


June 30,



2013



2012


2013



2012



(In thousands, except per share data)


























Revenues


$

235,383



$

215,513


$

494,605



$

451,399
















Operating costs and expenses:















Lease operating expenses



68,248




60,276



127,590




116,938

Gathering, transportation costs and production taxes



6,388




5,445



12,621




11,151

Depreciation, depletion, amortization and accretion



99,896




85,941



208,767




174,432

General and administrative expenses 



19,868




14,623



40,955




44,102

Derivative gain



(12,840)




(49,872)



(9,473)




(10,238)

Total costs and expenses



181,560




116,413



380,460




336,385

Operating income



53,823




99,100



114,145




115,014

Interest expense:















Incurred



21,536




14,706



42,770




28,612

Capitalized



(2,532)




(3,326)



(4,964)




(6,517)

        Income before income tax expense



34,819




87,720



76,339




92,919

Income tax expense 



12,423




34,153



27,325




36,134

        Net income


$

22,396



$

53,567


$

49,014



$

56,785































Basic and diluted earnings per common share


$

0.29



$

0.70


$

0.64



$

0.75
















Weighted average common shares outstanding



75,223




74,318



75,215




74,309
















Consolidated Cash Flow Information















Net cash provided by operating activities


$

127,528



$

113,168


$

297,362



$

241,325

Capital expenditures



162,587




102,658



299,213




187,284

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)


















Three Months Ended


Six Months Ended



June 30,


June 30,



2013



2012


2013



2012

Net sales volumes: 















Oil  (MBbls)



1,657




1,451



3,501




2,991

NGL (MBbls)



491




586



1,026




1,130

Oil and NGLs (MBbls)



2,148




2,037



4,527




4,120

Natural gas (MMcf)



11,842




14,320



24,562




28,696

Total oil and natural gas (MBoe)(1)



4,122




4,423



8,621




8,903

Total oil and natural gas (MMcfe)(1)



24,733




26,541



51,726




53,418
















Average daily equivalent sales (MBoe/d)



45.3




48.6



47.6




48.9

Average daily equivalent sales (MMcfe/d)



271.8




291.7



285.8




293.5
















Average realized sales prices (Unhedged): 















Oil ($/Bbl)


$

101.78



$

106.04


$

104.61



$

108.28

NGLs ($/Bbl)



32.17




44.27



33.26




46.31

Oil and NGLs ($/Bbl)



85.87




88.27



88.43




91.29

Natural gas ($/Mcf)



4.22




2.49



3.78




2.58

Barrel of oil equivalent ($/Boe)



56.88




48.71



57.22




50.57

Natural gas equivalent ($/Mcfe)



9.48




8.12



9.54




8.43
















Average realized sales prices (Hedged):(2) 















Oil ($/Bbl)


$

102.96



$

105.84


$

103.95



$

106.24

NGLs ($/Bbl)



32.17




44.27



33.26




46.31

Oil and NGLs ($/Bbl)



86.78




88.13



87.92




89.81

Natural gas ($/Mcf)



4.22




2.49



3.78




2.58

Barrel of oil equivalent ($/Boe)



57.36




48.64



56.95




49.89

Natural gas equivalent ($/Mcfe)



9.56




8.11



9.49




8.31
















Average per Boe ($/Boe):















Lease operating expenses 


$

16.56



$

13.63


$

14.80



$

13.13

Gathering and transportation costs and production taxes



1.55




1.23



1.46




1.25

Depreciation, depletion, amortization and accretion



24.23




19.43



24.22




19.59

General and administrative expenses 



4.82




3.31



4.75




4.95

Net cash provided by operating activities



30.94




25.58



34.49




27.11

Adjusted EBITDA



34.65




30.49



36.09




31.61
















Average per Mcfe ($/Mcfe):















Lease operating expenses


$

2.76



$

2.27


$

2.47



$

2.19

Gathering and transportation costs and production taxes



0.26




0.21



0.24




0.21

Depreciation, depletion, amortization and accretion



4.04




3.24



4.04




3.27

General and administrative expenses 



0.80




0.55



0.79




0.83

Net cash provided by operating activities



5.16




4.26



5.75




4.52

Adjusted EBITDA



5.78




5.08



6.02




5.27
















(1)

MMcfe and MBoe 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.

(2)

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

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Unaudited)











June 30,



December 31,



2013



2012



(In thousands, except



 share data)

Assets








Current assets:








Cash and cash equivalents


$

9,276



$

12,245

Receivables:








   Oil and natural gas sales



80,670




97,733

   Joint interest and other



22,921




56,439

   Income taxes



39,556




47,884

      Total receivables



143,147




202,056

Deferred income taxes



-




267

Prepaid expenses and other assets



37,214




25,555

        Total current assets



189,637




240,123

Property and equipment – at cost:








        Oil and natural gas properties and equipment (full cost method, of which $127,918 at June 30, 2013 and $123,503 at December 31, 2012 were excluded from amortization)



7,009,835




6,694,510

        Furniture, fixtures and other



20,848




21,786

            Total property and equipment 



7,030,683




6,716,296

        Less accumulated depreciation, depletion and amortization



4,851,973




4,655,841

            Net property and equipment 



2,178,710




2,060,455

Restricted deposits for asset retirement obligations



33,469




28,466

Other assets



18,198




19,943

        Total assets 


$

2,420,014



$

2,348,987









Liabilities and Shareholders' Equity








Current liabilities:








Accounts payable 


$

123,070



$

123,885

Undistributed oil and natural gas proceeds



42,068




37,073

Asset retirement obligations 



74,687




92,630

Accrued liabilities 



13,984




21,021

Deferred income taxes - current portion



5,760




-

        Total current liabilities



259,569




274,609

Long-term debt



1,099,537




1,087,611

Asset retirement obligations, less current portion



309,918




291,423

Deferred income taxes 



162,948




145,249

Other liabilities



5,864




8,908

Commitments and contingencies



-




-

Shareholders' equity:








Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,146,253 issued and 75,277,080 outstanding at June 30, 2013;  78,118,803 issued and 75,249,630 outstanding at December 31, 2012



1




1

Additional paid-in capital 



401,097




396,186

Retained earnings 



205,247




169,167

Treasury stock, at cost



(24,167)




(24,167)

        Total shareholders' equity 



582,178




541,187

        Total liabilities and shareholders' equity


$

2,420,014



$

2,348,987

















 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

 (Unaudited)












Six Months Ended




June 30,




2013



2012




(In thousands)






Operating activities:









Net income 


$

49,014



$

56,785


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









Depreciation, depletion, amortization and accretion 



208,767




174,432


Amortization of debt issuance costs and premium 



910




1,287


Share-based compensation



4,950




5,818


Derivative gain



(9,473)




(10,238)


Cash payments on derivative settlements 



(2,310)




(6,084)


Deferred income taxes



23,726




48,120


Asset retirement obligation settlements



(32,886)




(29,228)


Changes in operating assets and liabilities



54,664




433


        Net cash provided by operating activities



297,362




241,325











Investing activities:









Investment in oil and natural gas properties and equipment



(299,213)




(187,284)


Proceeds from sales of oil and natural gas properties and equipment 



-




30,453


Changes in restricted cash 



-




(30,763)


Purchases of furniture, fixtures and other



(981)




(668)


Net cash used in investing activities



(300,194)




(188,262)











Financing activities:









Borrowings of long-term debt 



252,000




197,000


Repayments of long-term debt 



(239,000)




(234,000)


Dividends to shareholders 



(12,795)




(11,898)


Other



(342)




(124)


Net cash used in financing activities  



(137)




(49,022)


Increase (decrease) in cash and cash equivalents  



(2,969)




4,041


Cash and cash equivalents, beginning of period



12,245




4,512


Cash and cash equivalents, end of period 


$

9,276



$

8,553




















 

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", "Adjusted EBITDA", and "Adjusted EBITDA Margin".  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 to Net Income Excluding Special Items

"Net Income Excluding Special Items" does not include the unrealized derivative (gain) loss, litigation accruals, and associated tax effects.  Net Income 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



Six Months Ended




June 30,



June 30,




2013



2012



2013



2012




(In thousands, except per share amounts)



(Unaudited)


















Net income


$

22,396



$

53,567



$

49,014



$

56,785


Unrealized commodity derivative gain



(10,879)




(50,157)




(11,783)




(16,322)


Litigation accruals



-




-




-




8,300


Income tax adjustment for above items at statutory rate



3,808




17,555




4,124




2,808


Net income excluding special items 


$

15,325



$

20,965



$

41,355



$

51,571



















Basic and diluted earnings per common share, excluding special items


$

0.20



$

0.28



$

0.54



$

0.68






































































Reconciliation of Net Income 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, and litigation accruals.  Adjusted EBITDA Margin represents the ratio of Adjusted EBITDA to total revenues.  We believe the presentation of EBITDA, Adjusted EBITDA, and Adjusted EBITDA Margin 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.  We believe this presentation is relevant and useful because it helps 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, Adjusted EBITDA, and Adjusted EBITDA Margin 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, Adjusted EBITDA, and Adjusted EBITDA Margin, as we calculate them, may not be comparable to EBITDA, Adjusted EBITDA, and Adjusted EBITDA Margin measures reported by other companies.  In addition, EBITDA, Adjusted EBITDA, and Adjusted EBITDA Margin do not represent funds available for discretionary use. 

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





















































Adjusted EBITDA



Three Months Ended



Six Months Ended




June 30,


June 30,




2013



2012



2013



2012




(In thousands)



(Unaudited)


















Net income


$

22,396



$

53,567



$

49,014



$

56,785


Income tax expense  



12,423




34,153




27,325




36,134


Net interest expense  



19,013




11,380




37,815




22,094


Depreciation, depletion, amortization and accretion



99,896




85,941




208,767




174,432


EBITDA



153,728




185,041




322,921




289,445



















Adjustments:

















Unrealized commodity derivative gain



(10,879)




(50,157)




(11,783)




(16,322)


Litigation accruals



-




-




-




8,300


Adjusted EBITDA


$

142,849



$

134,884



$

311,138



$

281,423




































Adjusted EBITDA Margin



61%




63%




63%




62%


 

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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