W&T Offshore Reports Third Quarter 2013 Financial and Operational Results And Callon Closing

HOUSTON, Nov. 6, 2013 /PRNewswire/ -- W&T Offshore, Inc. (NYSE: WTI) today announced financial and operational results for the third quarter of 2013.  Some of the highlights include:  

  • On October 17, we announced plans to acquire substantially all of Callon Petroleum's exploration and production properties in the Gulf of Mexico, including its 15% working interest in the Medusa field (deepwater Mississippi Canyon blocks 538 and 582) for $100 million, subject to post-effective date adjustments with an effective date of July 1, 2013.  On November 5, we closed on those properties that were not subject to third party preferential rights, which represented a substantial portion of the reserve value of the Callon transaction.  A final closing is anticipated by the end of November 2013 for those remaining properties, subject to preferential rights that have not been exercised.
  • Production volumes averaged 45.7 MBoe per day, or 274.4 MMcfe per day during the third quarter of 2013, up 13% over the third quarter of 2012.  Approximately 66% of our increase in revenues was attributable to higher production volumes.
  • Oil production for the third quarter increased 25.8% over the third quarter of last year.  Production volumes for the third quarter of 2013 were split 41.0% oil, 11.8% NGLs and 47.2% natural gas. 
  • Adjusted EBITDA was $147.2 million, up $37.5 million or 34% over the third quarter of last year, and Adjusted EBITDA Margin was 60%. 
  • Drilling operations are currently underway at the Noble operated Mississippi Canyon 782 #1 ("Dantzler") deepwater exploration well where W&T holds a 20% working interest.
  • Increased the capital budget for 2013 to $550 million to accommodate the addition of the Dantzler project, additional drilling at our Yellow Rose field, completion costs resulting from our successful exploration drilling, and new seismic and leasehold costs.
  • Revenues were $244.6 million, net income was $14.2 million and earnings of $0.19 per share.  Net income for the third quarter of 2013, adjusted to exclude special items, was $15.5 million or $0.20 per share. 
  • Average realized sales price was $106.70 per barrel for oil, $33.39 per barrel for NGLs and $3.66 per Mcf for natural gas.
  • Net cash provided by operating activities for the first nine months of 2013 was $475.8 million, up from $351.5 million for the comparable 2012 period. 
  • Completed three offshore wells during the quarter and are currently drilling two additional offshore wells  and completing one well.
  • Completed ten onshore wells in the Permian Basin of West Texas (one horizontal and eight vertical development wells, and one vertical exploration well) during the quarter.  After quarter close, we had one vertical well completed and six additional vertical wells awaiting completion.  We are currently drilling one horizontal exploration well in our Yellow Rose field in West Texas and one horizontal exploration well in East Texas at our Star Prospect.
  • A gas discovery at the deepwater prospect "Troubadour" in Mississippi Canyon 699.
  • Paid a dividend of $0.09 per share during the quarter.

Tracy W. Krohn, W&T Offshore's Chairman and Chief Executive Officer, stated, "Since the third quarter of last year, we increased our oil production by over 25% and increased our NGL production by almost 10%, with revenue from liquids production now making up 82% of total revenue.  We have achieved this growth both onshore and offshore, and through the drill bit as well as through acquisitions.  Significant contributors to this liquids expansion are our Mahogany field offshore, the Yellow Rose field in the Permian Basin and properties we acquired from Newfield Exploration in October 2012.  Our acquisition of oil dominated properties from Callon Petroleum will contribute to further growth in 2013, in addition to increasing our exposure to the deepwater. We now have almost 500,000 gross acres in the deepwater which we believe offers substantial opportunity for further expansion of our oil production and reserves."

Revenues, Production, and Price:  Revenues for the third quarter were $244.6 million compared to $185.9 million in the third quarter of 2012.  Overall, revenues increased due to higher production and better average commodity prices with the biggest contributors being higher oil production and higher oil prices.  During the third quarter of 2013, we sold 1.7 million barrels of oil, 0.5 million barrels of natural gas liquids (NGLs) and 11.9 billion cubic feet (Bcf) of natural gas as compared to 1.4 million barrels of oil, 0.5 million barrels of NGLs and 11.4 Bcf of natural gas for the same period of 2012.  In total, we sold 4.2 million barrels of oil equivalent (Boe) at an average realized sales price of $58.04 per Boe compared to 3.7 million Boe sold at an average realized sales price of $49.86 per Boe in the third quarter of 2012.  Oil revenues were higher due to a 25.8% increase in sales volumes and a 6.0% percent increase in prices.  NGL revenue increased due to a 20.7% increase in prices and a 9.5% increase in sales volumes. Natural gas revenues were higher primarily due to a 19.2% increase in prices and a 4.6% increase in sales volumes.  

Production for the third quarter of 2013 benefitted from the positive impact of our Ship Shoal 349 Mahogany production, increased production from our onshore Yellow Rose field and from the Newfield properties acquired in 2012.  Production was negatively impacted by natural production declines and production deferrals affecting various fields again in the third quarter of 2013.  The production deferrals were attributable to third-party pipeline outages, platform maintenance, and various operational issues.  We estimate that total production deferrals for the third quarter of 2013 were approximately 4.7 Bcfe.    Production was also deferred in the 2012 period by tropical storm activity as well as third party pipeline outages. 

Net Income & EPS:  Third quarter of 2013 net income was $14.2 million, or $0.19 per common share, compared to net loss of $1.5 million, or ($0.02) per common share, for the same period in 2012.  Net income for the third quarter of 2013, adjusted to exclude special items, was $15.5 million, or $0.20 per common share.  This compares to net income for the third quarter of 2012, excluding special items, of $14.4 million, or $0.19 per common share.  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  release.  Adjusted EBITDA for the third quarter of 2013 was $147.2 million, up from $109.7 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 nine months of 2013 was $475.8 million, compared to $351.5 million for the same period of the prior year.  During the nine months ended September 30, 2013, we made no income tax payments and received $59.1 million of refunds.  The refunds were primarily attributable to tax loss carrybacks to 2010 and 2011, and refunds of 2012 estimated federal tax payments.   

As of September 30, 2013, we have spent $45.3 million to date and expect to incur an additional $2.1 million for removal of wreckage associated with platforms damaged by Hurricane Ike.   

Lease Operating Expenses (LOE):  Lease operating expenses, which includes base lease operating expenses, insurance premiums, workovers and maintenance on our facilities, were $67.3 million in the third quarter of 2013 compared to the $53.4 million in the third quarter of 2012.  On a component basis, base LOE increased $8.9 million, workover expense increased $3.8 million and facilities maintenance increased $2.7 million, partially offset by a $1.5 million decrease in insurance premiums.  Base LOE increased primarily as a result of the addition of the properties acquired from Newfield during the fourth quarter of 2012, expanded onshore operations at our Yellow Rose field, and an ad valorem tax refund and other reductions that occurred in the 2012 period that did not reoccur in the 2013 period, partially offset by an increase in processing fees charged to third parties.  Workover costs increased with our expanded onshore activities and operations performed on the A-12 well at Mahogany.  The increase in facilities maintenance was primarily attributable to a planned maintenance turnaround of our Yellowhammer onshore gas plant during the quarter.    

Depreciation, Depletion, Amortization, and Accretion (DD&A): DD&A, including accretion for Asset Retirement Obligation (ARO), increased to $4.13 per Mcfe for the third quarter of 2013 from $3.47 per Mcfe in the prior year period.  On a nominal basis, DD&A increased to $104.1 million for the third quarter of 2013 from $77.5 million in the prior-year period.  DD&A rose on a nominal basis primarily due to increased production during the third quarter of 2013 when compared to the same period in 2012.  The rise in the rate per Mcfe continues to be related 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 significant 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 also contributed to the increase in our DD&A rate.  

General and Administrative Expenses (G&A):  G&A increased to $20.0 million for the third quarter of 2013 from $18.7 million for the prior-year period primarily due to increases in contract labor, professional fees and surety bond fees, partially offset by increased overhead billings to joint interest partners and lower compensation-related expenses. 

Derivatives:  For the third quarter of 2013 and 2012, our derivative net losses were $15.7 million and $24.7 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 third quarter of 2013, the net derivative loss was composed of a $4.6 million realized and an $11.1 million unrealized loss.  For the third quarter of 2012, the net derivative loss consisted of a realized loss of $0.9 million and an unrealized loss of $23.8 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 increased to $21.4 million for the third quarter of 2013 from $14.8 million for the prior-year period.  The aggregate principal amount of our 8.50% Senior Notes outstanding was $900.0 million in the third 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 third quarter of 2013 and 2012, $2.6 million and $3.4 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties.  The decrease is primarily attributable to reclassifying certain unevaluated properties to the full cost pool during the fourth quarter of 2012.

Other Income:  Included in Other Income is $9.2 million that represents a payment to W&T for an option exercised by a counterparty. 

Income Taxes: Income tax expense was $8.0 million for the third quarter of 2013, compared to a $2.2 million income tax benefit for the same period of 2012, primarily attributable to changes in pre-tax income.  Our effective tax rate for the three months ended September 30, 2013 was 36.1% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes. 

Capital Expenditures:  Our capital expenditures for the first nine months of 2013 were $423.1 million.  Capital expenditures were composed of $149.4 million for exploration, $246.1 million for development, and $27.6 million for leasehold and other costs.  Offshore activities accounted for 69% of the capital expenditures with 31% allocated to onshore activities.

Operations Review and Update 

OFFSHORE

Offshore Wells Completed in the Third Quarter 2013


Block/Well

WI%


Type

Location

Target


Comments











SS 349 A-14 ST2
(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 approximately 3,200 Boe per day net.











MP 108 B-1 ST

100


EXPL

Shelf

Gas and liquids in Tex W 6 sand at ~14,880' TVD


Well completed and currently producing. Additional pay discovered in the Tex W-3 sand will serve as future recomplete opportunity.











HI 21 A-1 BP1
(High Island 22 field)

100


DEV

Shelf

Gas and liquids at ~13,700' in the LH-20 sand


Well completed during the third quarter and final topside work was completed in October. Currently producing.



















Current Offshore Drilling and Completion Activity in the Fourth Quarter 2013


Block/Well

WI%


Type

Location

Target


Comments











MC 782 #1
(Dantzler)

20


EXPL

Deepwater

Exploration well with reservoir in Lower Miocene against salt


Active drilling operations.











MC 243 A-5
(Matterhorn)

100


EXPL

Deepwater

Target in "A" sand (producing reservoir) at ~6,800' TVD


Well logged ~220' of net pay. Active completion operations. First production expected during Q4 2013.











MC 699
(Troubadour)

20


EXPL

Deepwater

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


Gas discovery in 7,273' of water. Well T&A'd for future development.











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


Drilling operations to resume in November.











EC 321 A-2 ST

100


EXPL

Shelf

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


Well operations began in October.

 

OFFSHORE EXPLORATION AND DEVELOPMENT

Deepwater Gulf of Mexico

During the third quarter, we had a natural gas discovery at the deepwater exploration prospect, "Troubadour," in Mississippi Canyon ("MC") block 699, where we hold a 20% working interest.  The operator, Noble Energy, has sanctioned the MC 698 "Big Bend" discovery as a single well sub-sea tie back.  Long lead time equipment orders have commenced and first production is projected for 2015.

W&T has partnered with Noble Energy in an additional deepwater exploration well during 2013, the Mississippi Canyon 782 #1 "Dantzler" prospect, with a 20% working interest.  Noble estimates that the Dantzler prospect could have a targeted resource potential of between 50 and 220 million barrels of oil equivalent.  Drilling operations are underway and the well is scheduled to reach total depth during the fourth quarter, with results expected prior to year end.

Ship Shoal 349 "Mahogany" Field

As previously reported, we brought the SS 349 "Mahogany" A-14 exploration well online during July with production from the newly discovered T-sand.  The well has continued to show a strong drive mechanism and has produced an estimated 330,000 Boe gross and 275,000 Boe net (75% crude oil) in its first 90 days.  The company is making plans to drill another development well to recover the more than 200 feet of net pay uphole from the existing "T" sand completion in the M, N, O, and P sands. 

After completion of the A-14 well, we rig conducted a successful recompletion of the A-4 well to a new "P" sand which was brought online during early September at a rate of approximately 1,000 Boe per day gross. 

Following the A-4 recompletion, we spud the A-15 deep shelf, sub-salt exploratory well at Mahogany, which targets five separate stacked sands, including the N-sand and O-sand which both saw significant pay in the A-14 well logs.  After reaching the first casing point, drilling operations were temporarily suspended for a remedial workover on the A-12 producer.  This operation is expected to conclude soon at which time the A-12 will be placed back online and drilling operations will resume on the A-15 well.  We project the A-15 well will reach total depth during the first quarter of 2014.  Our estimated target reserve potential for this well is between 1.8 million and 6.2 million barrels of oil equivalent and the target initial production rate is approximately 1,400 Boe per day net to W&T after royalties.  The value associated with the Ship Shoal 349 field continues to grow with each new generation of seismic data and each new exploration discovery. 

Main Pass 108 Field

The B-1 side-track well at our Main Pass 108 field was brought online during August at an initial production rate of approximately 5,700 Mcfe per day gross and 100 barrels of oil gross.  Current production is from the Tex W-6 sand, which was the original target sand for the well.  The additional pay found in the Tex W-3 sand will serve as a future recompletion opportunity for this field.

Mississippi Canyon 243 "Matterhorn" Field

At our Matterhorn field, we have begun completion operations on the A-5 side-track well, which logged roughly 220 feet of net pay earlier this year.  We expect the completion operations to conclude and first production from the A-5 near the end of the fourth quarter of 2013.  Prior to the mobilization of the completion unit, the platform underwent various optimization activities and we performed a recomplete on the A-9 well.  Together, these activities enhanced production from the field which at the end of October was approximately 5,300 Boe per day, up significantly from last year.

High Island 22 Field

Completion operations and pipeline tie-back for the High Island 21 A-1 well took place during October, and the well was brought on production.  The well is producing from the LH-20 series sands.  The well discovered six separate pay zones, culminating in a total of approximately 225 net feet of pay.  The upper zones will serve as future recompletion opportunities and could result in reserve additions this year.

East Cameron 321 Field

At our East Cameron 321 field, the rig is now on location and has begun operations on our exploratory side-track well.  The target initial production rate is approximately 850 Boe per day net to W&T after royalties and is expected in the late fourth quarter.  Our target reserve potential for this project is 1.1 MMBoe.

West Cameron 73 #2

The 2012 discovery at our non-operated West Cameron 73 field is still expected to have final pipeline hook-up completed and first production during the fourth quarter of 2013. 


ONSHORE

Onshore Wells Completed in Third Quarter 2013


Project & Area

WI%

Type

# of Wells


Target


Comments

Permian Basin









Yellow Rose
Horizontal

100

DEV

1


Horizontal Wolfcamp "A"


1 well on flowback











Yellow Rose
80 Acre Verticals

100

DEV

8


4,500' vertical section in the Wolfberry


5 wells on production, 3 wells on flowback











Yellow Rose
40 Acre Verticals

100

EXP

1


4,500' vertical section in the Wolfberry


1 well on production



















Current Onshore Well Activity in the Fourth Quarter 2013


Project & Area

WI%

Type

# of Wells


Target


Comments

Permian Basin









Yellow Rose
80 Acre Verticals

100

EXP & DEV

5


4,500' vertical section in the Wolfberry


1 well completed and on flowback, 4 wells awaiting completion











Yellow Rose
40 Acre Verticals

100

DEV

1


4,500' vertical section in the Wolfberry


1 well awaiting completion











Yellow Rose
Horizontal

100

EXP

1


Horizontal Wolfcamp "B"


1 well drilling










Star Prospect









East Texas
Horizontal

97

EXP

1


Oil window of James Lime


1 well drilling

ONSHORE EXPLORATION AND DEVELOPMENT

Yellow Rose Project

During the third quarter, we continued to operate two rigs in the Permian Basin at our Yellow Rose field, completing nine new vertical wells (one of which was an exploration well) and one horizontal development well.  The third quarter average daily production was 3,944 Boe per day net to W&T after royalties.  This is up 63.5% over the average daily production rate in the third quarter of the previous year and is a 6.8% increase over the second quarter average daily production rate of 3,694 net Boe per day net to W&T after royalties.  We continue to see strong 30 day average initial production rates from our recent verticals and have continued with our 40 acre spacing tests.  As part of our expanded capital budget program, we expect to drill approximately seven additional vertical wells at Yellow Rose during the fourth quarter of 2013. 

Recently we spud the first horizontal Wolfcamp B well on our acreage in Martin County.  Nearby, offset operators have shown recent success with solid results from lateral lengths just over 4,000 feet as well as lateral lengths of over 7,000 feet.  Our initial Wolfcamp B horizontal well has a planned lateral length in excess of 6,000 feet.  We expect to complete the well and have results by year end. 

The northward expansion and growth in activity surrounding our acreage is reflective of not only the potential, but significant value tied to our current acreage position.  Although our current horizontal well is targeting the Wolfcamp B, we will continue to evaluate other potential benches which we may test in the coming months.  We continue to collect and analyze detailed data on those formations including log data and core data. 

Star Project 

At our Star Project in East Texas, we recently spud our fifth horizontal well targeting oil in the James Lime at about 8,500 feet true vertical depth with a planned lateral length of just over 6,000 feet.  We expect to complete the well during the fourth quarter.  We continue to monitor production from our initial four wells and are closely evaluating the activity of nearby operators in the area. 

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 results may be affected by the factors described below in "Forward-Looking Statements."

Estimated Production

Fourth Quarter

2013

Previous

Full-Year

2013

Revised

Full-Year

2013

Oil and NGLs (MMBbls)

2.2 – 2.5

9.0 – 9.5

9.0 – 9.3

   Natural Gas (Bcf)

12.7 – 14.4

47.4 – 49.5

49.2 – 50.9

      Total (Bcfe)

26.2 – 29.5

101.3 – 106.5

103.2 – 106.5

     Total (MMBoe)

4.4 – 4.9

16.9 – 17.7

17.2 – 17.7

Operating Expenses

($ in millions)

Fourth Quarter

2013

Previous

Full-Year

2013

 

Revised

Full-Year

2013 

Lease operating expenses

$65 - $75

$249 – $275

$260 - $270

Gathering, transportation, & production taxes

$5 - $9

$26 – $31

$23 - $27

  General & administrative

$19 - $25

$78 – $86

$80 - $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, November 7, 2013 at 9:30 a.m. Eastern Time.  To participate, dial (480) 629-9770 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 November 14, 2013 and may be accessed by calling (303) 590-3030 and using the pass code 4645500#.

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 (60 producing and seven 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 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 on Form 10-Q for the quarter ended June 30, 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. 

CONTACT: 

Mark Brewer 

Danny Gibbons


Investor Relations 

SVP & CFO


investorrelations@wtoffshore.com 

  investorrelations@wtoffshore.com

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES 

Condensed Consolidated Statements of Income (Loss)

(Unaudited)


















Three Months Ended


Nine Months Ended



September 30,


September 30,



2013



2012


2013



2012



(In thousands, except per share data)


























Revenues 


$

244,555



$

185,946


$

739,160



$

637,345
















Operating costs and expenses:















Lease operating expenses  



67,346




53,411



194,935




170,349

Gathering, transportation costs and production taxes



5,418




4,163



18,038




15,314

Depreciation, depletion, amortization and accretion



104,143




77,462



312,911




251,894

General and administrative expenses 



20,024




18,691



60,979




62,793

Derivative loss



15,659




24,659



6,186




14,421

    Total costs and expenses



212,590




178,386



593,049




514,771

    Operating income



31,965




7,560



146,111




122,574

Interest expense:















Incurred



21,373




14,791



64,157




43,409

Capitalized



(2,573)




(3,383)



(7,537)




(9,899)

Other income



9,062




202



9,075




210

  Income (loss) before income tax expense (benefit) 



22,227




(3,646)



98,566




89,274

Income tax expense (benefit) 



8,033




(2,175)



35,358




33,959

  Net income (loss) 


$

14,194



$

(1,471)


$

63,208



$

55,315































Basic and diluted earnings (loss) per common share


$

0.19



$

(0.02)


$

0.83



$

0.73
















Weighted average common shares outstanding



75,233




74,327



75,221




74,315
















Consolidated Cash Flow Information















Net cash provided by operating activities


$

178,471



$

110,164


$

475,833



$

351,489

Capital expenditures



123,879




125,088



423,092




312,372

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)
















Three Months Ended








September 30,





   Variance



2013



2012


Variance


Percentage(2)

Net sales volumes: 













Oil  (MBbls) 



1,725




1,371



354


25.8%

NGL (MBbls) 



494




451



43


9.5%

Oil and NGLs (MBbls)



2,220




1,822



398


21.8%

Natural gas (MMcf) 



11,924




11,401



523


4.6%

Total oil and natural gas (MBoe)(1)



4,207




3,722



485


13.0%

Total oil and natural gas (MMcfe)(1)



25,241




22,331



2,910


13.0%














Average daily equivalent sales (MBoe/d)



45.7




40.5



5.2


12.8%

Average daily equivalent sales (MMcfe/d)



274.4




242.7



31.7


13.1%














Average realized sales prices (Unhedged): 













Oil ($/Bbl)


$

106.70



$

100.68


$

6.02


6.0%

NGLs ($/Bbl)



33.39




27.66



5.73


20.7%

Oil and NGLs ($/Bbl)



90.38




82.62



7.76


9.4%

Natural gas ($/Mcf)



3.66




3.07



0.59


19.2%

Barrel of oil equivalent ($/Boe)



58.04




49.86



8.18


16.4%

Natural gas equivalent ($/Mcfe)



9.67




8.31



1.36


16.4%














Average per Boe ($/Boe):













Lease operating expenses 


$

16.01



$

14.35


$

1.66


11.6%

Gathering and transportation costs and production taxes



1.29




1.12



0.17


15.2%

Depreciation, depletion, amortization and accretion



24.76




20.81



3.95


19.0%

General and administrative expenses 



4.76




5.02



(0.26)


-5.2%

Net cash provided by operating activities



42.42




29.60



12.82


43.3%

Adjusted EBITDA



34.99




29.48



5.51


18.7%














Average per Mcfe ($/Mcfe):













Lease operating expenses 


$

2.67



$

2.39


$

0.28


11.7%

Gathering and transportation costs and production taxes



0.21




0.19



0.02


10.5%

Depreciation, depletion, amortization and accretion



4.13




3.47



0.66


19.0%

General and administrative expenses 



0.79




0.84



(0.05)


-6.0%

Net cash provided by operating activities



7.07




4.93



2.14


43.4%

Adjusted EBITDA



5.83




4.91



0.92


18.7%

 

(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)

Variance percentages are calculated using rounded figures and may result in slightly different figures for comparable data.

 

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Operating Data

(Unaudited)
















Nine Months Ended








September 30,





   Variance



2013



2012


Variance


Percentage(2)

Net sales volumes: 













Oil  (MBbls) 



5,226




4,361



865


19.8%

NGL (MBbls) 



1,520




1,581



(61)


-3.9%

Oil and NGLs (MBbls)



6,747




5,942



805


13.5%

Natural gas (MMcf) 



36,486




40,097



(3,611)


-9.0%

Total oil and natural gas (MBoe)(1)



12,828




12,625



203


1.6%

Total oil and natural gas (MMcfe)(1)



76,967




75,749



1,218


1.6%














Average daily equivalent sales (MBoe/d)



47.0




46.1



0.9


2.0%

Average daily equivalent sales (MMcfe/d)



281.9




276.5



5.4


2.0%














Average realized sales prices (Unhedged): 













Oil ($/Bbl)


$

105.30



$

105.89


$

(0.59)


-0.6%

NGLs ($/Bbl)



33.30




40.99



(7.69)


-18.8%

Oil and NGLs ($/Bbl)



89.07




88.63



0.44


0.5%

Natural gas ($/Mcf)



3.74




2.72



1.02


37.5%

Barrel of oil equivalent ($/Boe)



57.49




50.36



7.13


14.2%

Natural gas equivalent ($/Mcfe)



9.58




8.39



1.19


14.2%














Average per Boe ($/Boe):













Lease operating expenses 


$

15.20



$

13.49


$

1.71


12.7%

Gathering and transportation costs and production taxes



1.41




1.21



0.20


16.5%

Depreciation, depletion, amortization and accretion



24.39




19.95



4.44


22.3%

General and administrative expenses 



4.75




4.97



(0.22)


-4.4%

Net cash provided by operating activities



37.09




27.84



9.25


33.2%

Adjusted EBITDA



35.73




30.98



4.75


15.3%














Average per Mcfe ($/Mcfe):













Lease operating expenses 


$

2.53



$

2.25


$

0.28


12.4%

Gathering and transportation costs and production taxes



0.23




0.20



0.03


15.0%

Depreciation, depletion, amortization and accretion



4.07




3.33



0.74


22.2%

General and administrative expenses 



0.79




0.83



(0.04)


-4.8%

Net cash provided by operating activities



6.18




4.64



1.54


33.2%

Adjusted EBITDA



5.96




5.16



0.80


15.5%

 

(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)

Variance percentages are calculated using rounded figures and may result in slightly different figures for comparable data.

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(Unaudited)











September 30,



December 31,



2013



2012



(In thousands, except



 share data)

Assets








Current assets:








Cash and cash equivalents


$

15,227



$

12,245

Receivables:








   Oil and natural gas sales



85,221




97,733

   Joint interest and other



31,492




56,439

   Income taxes



-




47,884

      Total receivables



116,713




202,056

Restricted cash and cash equivalents



16,459




-

Prepaid expenses and other assets



32,850




25,822

  Total current assets



181,249




240,123

Property and equipment – at cost:








  Oil and natural gas properties and equipment (full cost method, of which $129,584 at 








September 30, 2013 and $123,503 at December 31, 2012 were excluded from 








amortization)



7,120,086




6,694,510

  Furniture, fixtures and other



21,325




21,786

     Total property and equipment



7,141,411




6,716,296

  Less accumulated depreciation, depletion and amortization



4,950,768




4,655,841

     Net property and equipment



2,190,643




2,060,455

Restricted deposits for asset retirement obligations



34,966




28,466

Other assets



16,842




19,943

  Total assets


$

2,423,700



$

2,348,987









Liabilities and Shareholders' Equity








Current liabilities:








Accounts payable


$

129,988



$

123,885

Undistributed oil and natural gas proceeds



41,278




37,073

Asset retirement obligations  



95,014




92,630

Accrued liabilities



51,048




21,021

  Total current liabilities



317,328




274,609

Long-term debt



1,052,984




1,087,611

Asset retirement obligations, less current portion



267,093




291,423

Deferred income taxes



177,404




145,249

Other liabilities



15,859




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 September 30, 2013;  78,118,803 issued and 








75,249,630 outstanding at December 31, 2012



1




1

Additional paid-in capital



404,604




396,186

Retained earnings



212,594




169,167

Treasury stock, at cost



(24,167)




(24,167)

  Total shareholders' equity



593,032




541,187

  Total liabilities and shareholders' equity


$

2,423,700



$

2,348,987

 

W&T OFFSHORE, INC. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

 (Unaudited)












Nine Months Ended




September 30,




2013



2012




(In thousands)






Operating activities:









Net income  


$

63,208



$

55,315


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









Depreciation, depletion, amortization and accretion 



312,911




251,894


Amortization of debt issuance costs and premium 



1,366




2,046


Share-based compensation   



8,457




9,137


Derivative loss   



6,186




14,421


Cash payments on derivative settlements   



(6,855)




(6,960)


Deferred income taxes   



31,581




44,465


Asset retirement obligation settlements   



(59,188)




(63,150)


Changes in operating assets and liabilities 



118,167




44,321


  Net cash provided by operating activities 



475,833




351,489











Investing activities:









Investment in oil and natural gas properties and equipment 



(423,092)




(312,372)


Proceeds from sales of assets and other, net 



21,011




30,453


Change in restricted cash 



(16,459)




(24,026)


Deposit for acquisition



-




(22,800)


Purchases of furniture, fixtures and other 



(1,327)




(2,125)


Net cash used in investing activities 



(419,867)




(330,870)











Financing activities:









Borrowings of long-term debt 



335,000




316,000


Repayments of long-term debt 



(368,000)




(314,000)


Dividends to shareholders 



(19,570)




(17,848)


Debt issuance costs



(164)




(2,081)


Other



(250)




(209)


Net cash used in financing activities 



(52,984)




(18,138)


Increase in cash and cash equivalents 



2,982




2,481


Cash and cash equivalents, beginning of period 



12,245




4,512


Cash and cash equivalents, end of period 


$

15,227



$

6,993


 

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, a contract option fee, 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. 







































































Three Months Ended



Nine Months Ended




September 30,



September 30,




2013



2012



2013



2012




(In thousands, except per share amounts)



(Unaudited)


















Net income (loss) 


$

14,194



$

(1,471)



$

63,208



$

55,315


Unrealized commodity derivative (gain) loss 



11,114




23,784




(669)




7,461


Contract option fee 



(9,065)




-




(9,065)




-


Litigation accruals 



-




700




-




9,000


Income tax adjustment for above items at statutory rate



(717)




(8,569)




3,407




(5,761)


Net income excluding special items


$

15,526



$

14,444



$

56,881



$

66,015



















Basic and diluted earnings per common share, excluding special items


$

0.20



$

0.19



$

0.75



$

0.87





















































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, a contract option fee, 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.
























































































Three Months Ended



Nine Months Ended




September 30,


September 30,




2013



2012



2013



2012




(In thousands)



(Unaudited)


















Net income (loss)


$

14,194



$

(1,471)



$

63,208



$

55,315


Income tax expense (benefit)



8,033




(2,175)




35,358




33,959


Net interest expense



18,798




11,406




56,613




33,500


Depreciation, depletion, amortization and accretion



104,143




77,462




312,911




251,894


EBITDA



145,168




85,222




468,090




374,668



















Adjustments:

















Unrealized commodity derivative (gain) loss



11,114




23,784




(669)




7,461


Contract option fee



(9,065)




-




(9,065)




-


Litigation accruals



-




700




-




9,000


Adjusted EBITDA


$

147,217



$

109,706



$

458,356



$

391,129




































Adjusted EBITDA Margin



60%




59%




62%




61%


SOURCE W&T Offshore, Inc.



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