W&T Offshore Inc (WTI) 2010 Q1 法說會逐字稿

Good Day ladies and gentlemen. Thank you for standing by. Welcome to the W&T Offshore first quarter 2010 earnings conference call. During today's presentation, all parties will be in a listen-only mode. Following the presentation the conference will be open for questions. (Operator Instructions) This conference is being recorded today, Tuesday, the 4th of May, 2010. I would now like to turn the conference over to Janet Yang, Finance Manager, W&T Offshore. Please go ahead.

Thank you, operator, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review the first quarter 2010 results. Before I turn the call over, I have a few items to go over. If you would like to be on the Company's e-mail distribution list to receive future news releases or you experience a technical problem and didn't receive yours, please call DRG&E's office at 713-529-6600 and someone will be glad to help you. If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Investor Relations section of the Company's website at www.wtoffshore. com, or via recorded replay until May 11, 2010. To use the replay feature, call 303-590-3030, and dial the pass code 4285677. Information recorded on this call speaks only as of today, May 4, 2010, and therefore time sensitive information may no longer be accurate as of the date of any replay. Please refer to the first quarter 2010 earnings release for our disclosure on forward-looking statements. Now, I would like to turn the call over to Mr. Tracy Krohn, W&T's Chairman and CEO.

Thanks, Janet, good morning, everyone. Thanks for joining us on our conference call today. Here with me today are Danny Gibbons, our Chief Financial Officer, Jeff Durrant, our Senior VP of Exploration and Geosciences, and Steve Schroeder, our Chief Operating Officer. Also, Jamie Vazquez, our President, will be here for the Q&A session as well.

This morning, we're going to review some of the key events that took place in the first quarter, as well as discuss our recently completed acquisition and our outlook for the balance of 2010. We're very pleased with our first quarter results and we've seen continued growth in our operating income, driven by higher commodity prices and lower operating costs. With 50% of our production in oil, we've gained a significant benefit from higher oil prices. That's contributed to a 44% increase in revenue in the first quarter compared to the first quarter of last year, adjusted EBITDA increased 127% to $119 million from $52.5 million during the first quarter of 2009, and earnings per share was up significantly as well to $0.57 per share, or $0.49 excluding special items from the loss per share of $1.34 for the quarter last year, also excluding special items. Danny's going to walk through the first quarter numbers in more detail later. Some of the more interesting and good news occurred after the end of the quarter.

First -- the first item of importance is that we closed the acquisition from Total to acquire two deep water producing fields. Let me describe that for you. We've acquired 100% working interest in Mississippi Canyon Block 243, that's the Matterhorn field, and a 64% working interest in the Viosca Knoll blocks 822 and 823. That's the Virgo field from Total. The transaction closed on April 30, with an effective date of January 1, so we'll enjoy the benefit of that production in the second quarter. Also note that the purchase price of $150 million was adjusted for, among other things, net revenue and operating expenses from the effective date to the closing date, and a down payment of $7.5 million, resulting in W&T paying $117.5 million at closing from cash on hand. We're very happy about adding these strategic deep water assets to our portfolio, both the Matterhorn and Virgo fields have been highly productive and the net average daily production rate for March was 3,800 barrels of oil and 11 million cubic feet of natural gas net. That's 56,064 barrels of oil equivalent per day or approximately 34 million cubic feet equivalent per day. As we've said, these properties meet our acquisition criteria, as they have good cash flow, they are financeable, we have a lot of upside potential and future exploitation as well. We see growth opportunity in both fields for recompletions of the Hyne pipe reserve, work overs and longer term for the potential of additional wells.

We also believe we can operate the properties efficiently and benefit from revenue streams associated with these strategically located production facilities in the deep water of the Gulf of Mexico. The proximity of the Virgo platform in particular to some of our deep water prospects will position us to bring potential nearby future discoveries on production more effectively and efficiently. To complement the acquisition, we have recently acquired a lease covering Viosca Knoll 779, a deepwater block that is adjacent to the Virgo platform. We plan to talk more about those projects in the future. In addition, we've been approached by third parties requesting access to our facilities, which would also help lower our operating costs. Based on estimates prepared by Netherland, Sewell & Associates, effective January 1, 2010, proved reserves associated with the acquisition were 11.6 million barrels of oil equivalent, 64% are from oil or natural gas liquids. The implied purchase price of $12.90 per barrel of oil equivalent for the estimated proved reserves represents really good value, and is very competitive with the deals done over the last few months. We estimate that the probable reserves are approximately eight million barrels of oil equivalent. It's 47.8 Bcf equivalent, and that the possible reserves almost twice that amount, about 14.8 million barrels of oil equivalent, or 88.7 Bcf equivalent. Like I said, we're pleased with this acquisition.

Also of major importance since the end of the first quarter, our lenders just recently affirmed, or reaffirmed our borrowing base at $405.5 million. We'll continue to have excellent liquidity to pursue future opportunities for growth. As you may have also seen in yesterday's press release, we declared a cash dividend of $0.03 per share to holders of record on May 26, 2010, with payment date of June 23, 2010. Having said that, I'll turn it over to Danny to further explain the results of the first quarter.

Thanks, Tracy. Good morning, everyone. I'm going to take a few minutes to point out some special items and provide some sequential comparisons. You'll find year-over-year comparisons of our quarterly financials in the earnings announcement we released this morning. Revenues for the first quarter were $169.6 million, down a bit from the $176.1 million reported in the fourth quarter last year. This was due to lower production volumes partially offset by higher average realized sales prices per Mcfe. Production averaged 222 Mmcfe per day in the first quarter of 2010 compared to 249 million per day in the fourth quarter. The production decrease primarily results from the sale of various non-core assets during 2009, which for parts of 2009 were producing around 35 million per day. Also, please bear in mind that the first quarter production volumes do not reflect volumes produced from the recently acquired Matterhorn and Virgo fields. Our averaged realize sales price for oil increased to $69.95 per barrel in the first quarter, from $69.47 per barrel in the fourth quarter of last year. And the average sales price for natural gas increased to $5.38 per Mcf from $3.92 per Mcf for the comparable periods.

Our increasing ratio of oil and natural gas liquids production versus natural gas, which is now 50% significantly enhances the blended average sales price resulting in $8.50 per Mcfe for the first quarter compared with $7.67 per Mcfe during the fourth quarter of 2009. Also of note, in the first quarter, revenues from the sale of our oil and natural gas liquids accounted for 68% of total revenues, even though production is equally split between oil and natural gas due to the strong oil price realized in the first quarter. Obviously that strength in crude oil prices has continued into the second quarter, and based on the forward curve, oil prices look great for the rest of the year. Adjusted EBITDA increased 5% to $119 million from $113.9 million in the fourth quarter. The growth in adjusted EBITDA is largely attributable to lower operating costs. We were pleased to see an improvement in our EBITDA margins, which increased to 70% from 65% in the fourth quarter.

Now let me move on to the discussion of lease operating expense, or LOE. Just as a reminder, internally we split LOE into five components. Base LOE, insurance premiums, work overs, facilities work, and hurricane remediation. Sequentially total LOE was down 23% to $35.4 million. Base LOE was over 17% lower due to divestitures in 2009 and our cost reduction initiatives. LOE also benefited in the first quarter from adjustment to our estimated hurricane remediation costs and insurance reimbursements of $5.4 million, over fourth quarter 2009 and both of these are related to Hurricane Ike. Partially offsetting these decreases were $2 million of additional workover activity compared to the fourth quarter. As it relates to LOE going forward, we will have new costs associated with operating the recently acquired Matterhorn and Virgo platforms. Our existing base operating expenses will be down for the year due to the divestitures of the current 2009 and our cost reduction efforts.

Now, let me turn to liquidity. Our cash balance at March 31 was $84.2 million, up $46 million from last quarter, and we had undrawn capacity of $405.5 million on our revolving credit facility. We continued to build cash during the quarter, and our net cash provided by operating activities for the first quarter was $87 million. As we have done in the past, during the first quarter, we drew on the revolver to generate interest income to help offset the effects of the interest rate swap we have in place. At the end of the quarter, we repaid the revolver, but have again drawn it down and as of this morning, have a cash balance of $142 million. We expect to continue to use the revolving credit facility to generate interest income until the swap expires in August of 2010. To reconcile the changes in the cash balance from the end of the year to the first quarter, cash flow from operations, before changes in working capital, was $109.3 million, and net cash used in investing activities was $38.7 million, all of which relates to investments in oil and gas properties. We also reduced accounts payable significantly, but had some other working capital changes that were positive, the net effect of which resulted in net cash outflow of $22.4 million. In addition, we spent $2.2 million on common stock dividends.

As Tracy mentioned, we just completed the semi annual redetermination of our borrowing base, which, again, has been reaffirmed at $405.5 million. In regards to capital expenditures, during the first quarter, our capital spending for oil and natural gas properties and equipment of $39.9 million included $19.4 million for exploration activities, $17.3 million for development activities, and $3.2 million for seismic capitalized interest and other lease hold costs. Our exploration and development capital expenditures consisted of $30.7 million on the conventional shelf and other projects, $1.7 million in the deep water, and $4.3 million on the deep shelf. Let me also say as part of acquiring the Total assets, we have assumed some additional P&A liability. The present value of the Asset Retirement Obligation or the ARO that we will record in our next published financial statement is expected to be around $6.5 million for these assets. Let me discuss insurance claims, receivables and claims for a moment. For the first quarter of 2010, we added $8.4 million to our insurance receivables for costs incurred that have been approved for reimbursement under our insurance policies, and we received another $9 million in insurance reimbursements associated with hurricane-related LOE and plug and abandonment activity.

On a couple of tax-related issues, we filed refund claims with the IRS to carry back net operating losses to recruit prior year taxes. We anticipate receiving a refund of $9.1 million in the second quarter of 2010, and expect an additional $78.3 million in tax refunds in the fourth quarter. Our effective tax rate for the first quarter was approximately 8.7%, primarily related to a decrease in our valuation allowance for deferred tax assets, in addition to adjustments for prior year taxes and other discreet items. Our forecasted taxable income for 2010 has allowed us to reduce a portion of our valuation allowance. Finally, during the first quarter of 2010, we entered in to a 2A collars relating to approximately four Bcf of our anticipated production in 2010, and seven Bcfe of our 2011 anticipated production. As of March 31, 2010, our derivative instruments consisted of 2A collars and a commodity swap contract relating to approximately 16 Bcfe of our anticipated production during the remainder of 2010, and approximately seven Bcfe of anticipated reduction in 2011. Next Raleigh, the contracts we entered into during the quarter were all oral-related positions that are 2A collars with floors at $75 per barrel and ceilings as high as $93.25 for 2010, and $96.50 per barrel in 2011. All in all, these hedges really help, with our credit and liquidity position and provide good support to our capital expenditures program. And with that, I'll turn the call over to Jeff Durrant. Jeff?

Thanks, Danny, and good morning to everyone. Let me start with an update on our exploration and development drilling program. As announced earlier, W&T has planned an additional 10-well drilling program, nine of the 10 wells are exploration and one of which will be a development well. In the first quarter, we participated in the drilling of three wells. The first well, Eugene Island 95-20ST -- was a successful exploration well in the conventional shelf and found 26 feet of natural gas and full to base-- we have a 23% working interest in this non-operated well, which was put on production in late April and while not full, to full rate yet, it is currently producing about 2.9 million cubic feet equivalent per day gross. The second well, High Island 129-16ST was a successful development well in which we own a 10% working interest. We found 34 feet of natural gas and full to base. This well was also put on production in mid-April and is currently producing at a gross rate of about 10 million cubic feet of gas per day and about 100 barrels of oil per day. We also drilled the noncommercial Viosca Knoll 734 A- 4.

Although this well was deemed noncommercial, additional geological information obtained on this well extended the boundaries of a similar reservoir developed in the adjacent main path 283 wells in last year's drilling program onto the BK 734 lease. As a result, the A-2 well on this platform was recompleted to this reservoir in an up structure position, which should allow us to book additional reserves. Also, since the rig was on location, the additional space and horsepower allowed us to remove an obstruction in an inactive well and bring it back online. And consequently, the total net production from the platform has increased by approximately 1,800 barrels of oil equivalent per day from this activity. After the end of the first quarter, we drilled and reached total depth in the Main Pass 98-1 well. This is an exploration well on the conventional shelf. Well drilled to a total depth of about 12,600 feet and found approximately 55 feet of gas condensate in three sands. We took a gas condensate sample along the side wall cores and log analysis, which indicated high quality sand in all three productive intervals. Also in the main pass area, we are currently drilling two additional wells. In April, we spudded the Main Pass 283 A-6ST. This is an exploratory well, and last week, we moved on location for the Main Pass 108E-3, an exploratory well, which is targeted untested amplitudes, similar to existing field pay zones.

To date, we drilled or are currently drilling six of the 10-well program, the unrisked, most liked reserves for 10-well program is currently estimated to be about 146 Bcfe. The remaining four wells are all exploration wells and are located on the conventional shelf, onshore Louisiana, and one well in the deep water. Because there seems to be a lot of curiosity about our drilling projects onshore, I would like to talk about one of the wells that we will be participating in drilling. That is expected to spud in June. This well's proposed to a total depth of 18,500 feet and is targeting the Camerina formation We will have a 50% working interest in the well as a non-operator. If this well is successful, we could expect to have production online as early as the end of the year. This has potentially large reserves and competes favorably with our offshore projects on full cycle economics. Strategically, we have focused our exploration team on higher impact projects located on the shelf, deep water Gulf of Mexico, as well as the onshore. Meanwhile, our exploration, exploitation team will focus on developing our development of our existing fields and projects. With the focus on reserve and production growth, we expect to add additional wells to our 2010 drilling program, as the year progresses. With that, I'll turn the call back over to Steve Schroeder.

Thanks, Jeff. To summarize operations so far in 2010, we've drilled or are currently drilling six wells. Five are exploration and one is a development well. In addition, we did 12 recompletes that added approximately 34 million cubic feet equivalent per day, net initial incremental production at a cost of $13 million. We also did five work overs for $3.4 million that added approximately nine million cubic feet equivalent per day net initial incremental production. We plan to continue this active workover and recompletion program throughout 2010 and have budgeted to spend another $33 million.

Let me update you on production. Our first quarter production of 20 Bcfe came in above the high end of our guidance of 19.7 Bcfe. This was primarily due to the positive impact of our recomplete and workover program. This solid incremental production growth helped to offset the loss of production from the divestiture of various non-core assets in 2009, a limited 2009 drilling budget, and the unexpected loss of production of our Green Canyon 646 Daniel Boone well. As you may recall, production from the Daniel Boone project commenced at the end of third quarter of last year. In our conference call last quarter, we reported that we plan to recomplete the Green Canyon 646 well in March to a different zone utilizing smart technology. During March, we did recomplete the well to the new zone at a minimal cost. Production from the new zone came on at 2,800 barrels per day. However, the decrease in production -- excuse me, decrease in pressure we experienced in the earlier zone recurred in this zone, shutting in the well. We are continuing to analyze the well's production and pressure data, as well as seismic information to develop future plans. The fact that the Daniel Boone well is shut in is reflected in our forward production guidance.

Relative to production guidance, in the second quarter of 2010, we will see the impact of additional production from our acquisition of the Matterhorn and Virgo platforms from Total from the April 30 closing date and thereafter. Production from the January 1 effective date to the April 30 closing date resulted in a reduction of the purchase price and the amount of the reserves that we will book. The net average daily production from the acquired assets for March was 3,800 barrels of oil per day and 11 million cubic feet of natural gas per day. However, since the acquisition didn't close until April 30, we will not see the full impact of the acquisition until the third quarter. Prior to bringing on Matterhorn and Virgo, our production was running about 200 million cubic feet per day in April. Volumes have been lower than the first quarter, due to various pipeline outages and decreased production from Daniel Boone. Based on the factors above, we now expect our second quarter production guidance to be between 1.4 million and 1.6 million barrels of oil and between 9.8 billion and 10.9 billion cubic feet of natural gas for a total of between 18.4 billion and 20.6 billion cubic feet of gas equivalent. As you see, because the production from the assets we acquired from Total is about 67% oil, it has helped to increase our oil to gas production ratio.

For all of 2010, we now anticipate production to be between 5.6 million and 7.6 million barrels of oil and between 36.6 billion and 49.5 billion cubic feet of natural gas for a total of between 70.3 billion and 95.1 billion cubic feet of gas equivalent, up from our production guidance -- our prior guidance of 60 Bcfe to 80 Bcfe for the year. Please keep in mind that our guidance only relates to our 10-well program and the acquired assets, and does not reflect any buildup from the remainder of our capital budget. Shifting to lease operating expenses, our guidance for LOE in the second quarter is expected to be between $50 million and $61 million, and between $177 million and $216 million for the full year of 2010. These estimates do not include allowances for hurricane-related expenses or insurance reimbursements, but do include the impact of operating the Matterhorn and Virgo platforms from April 30 forward. Gathering and transportation and production taxes for the second quarter of 2010 are now expected to be between $4 million and $5 million, and between $18 million and $22 million for the full year. Now, let me turn it over to Tracy for closing remarks. Tracy?

Thanks, Steve. Before we take your questions, I would like to talk a bit more about our plans for the balance of the year. We've been very active so far this year and we spent a dedicated $326 million of our 2010 capital expenditure budget of $450 million. Among our accomplishments we've completed an acquisition at an attractive valuation, drilled some good wells. We've added production through less expensive recompletion and workover projects. We're currently evaluating some multiple high impact drilling opportunities located onshore Louisiana, in the deep water, on the continental shelf, and other acquisitions as well. We expect to spend all of the $450 million capital budget on these types of projects and/or acquisitions. We expect to remain disciplined. We don't intend to chase an acquisition beyond a price that we think makes good sense.

Our inventory of drilling projects, access to joint ventures, and the potential for future acquisitions gives us the flexibility to do what we think will add the most value to our shareholders. Also, bear in mind that our borrowing base was just reaffirmed at $405.5 million. To date, none of our operations have been affected by the spill at the macondo well at Mississippi Canyon 252. We empathize with the families of the deceased. It's a terrible accident that has occurred here. We hope that all parties involved with this leak will be able to solve the problem sooner rather than later. We are willing to help in any way, as most Companies would in our industry. Now, with that, we would be glad to take your questions. Operator, please open the phone lines for Q&A.

Thank you. (Operator Instructions) Our first question is from the line of Scott Hanold with RBC Capital Markets. Please go ahead.

Thanks. Hi, Tracy. How's it going?

Great Scott. How are you, sir?

Pretty good. A little bit more on the Gulf of Mexico operation, it does look like where the macondo well is there at least the oil is drifting, sort of, could impact some of your operations in Main Pass and Viosca Knoll as well as some of the acquired properties. What are you being told right now by the MMS or anybody else that's kind of looking at that stuff? What would happen if that oil slick start moving towards your platforms? Would you need to shut those down?

Well, I think that's a matter of how much oil is in the area and what the fumes are, the dangers of the fumes coming off of the crude on the water. So as long as that doesn't get to concentrations that are too high, we'll continue to operate. We've not been asked to shut down. We've not been alerted to anything of that sort. Certainly we would in the event of safety, if that were the issue. But, but we have quite a bit of production out in the Gulf of Mexico and we've not been asked to shut anything down at this point.

Okay, okay. Thanks. And in -- take a look at your portfolio, and you do have some decent liquidity at this point, how do you feel -- you've always been an acquire and exploit-- assertive have an acquire and exploit background, but when you look at your organic opportunities and essentially starting to do some stuff onshore -- how do you look at your opportunities so that you can go forward? Would you rather be a little bit more organic or do you think there's a better opportunities on the acquisition side?

Scott, I've had this question asked many times. I don't care whether it's organic or whether it's acquisition. All I really care about is whether it makes money. I've always tried to look at our projects, as to whether they make money on full cycle economics. We're not, we're not involved in, in the idea of borrowing money to drill with and mortgaging our future. So I don't really care. Most of the stuff that we have kind of pushes us toward things that are oily. So that's kind of the direction we're heading right now, because that's, that's where the economics dictate. Remember that in order to be successful with gas play, you just have more molecules in the ground.

Okay, I guess this is kind of a follow-up to that. When you look at planned activity levels going forward in this year, basically as you look at your CapEx spend versus your cash flow, I guess I'm just trying to reconcile. Looks like your relative organic activity levels are a little bit softer than they were, say, a few years back. So how do you, how should I view that?

All right. Well, let me -- maybe I didn't emphasize that enough for you in the text here. But we are looking at some higher impact prospects, both deep water and onshore, and out in the shelf. So expect to see some of that come to fruition in more near term than far term. I can't give you an exact forecast of when that will be, but I expect that it's coming. We've tried to forecast the market that we expect we'll be doing some more drilling here in the near term. However, those are not things that have to be done right away. The good news is that we have that flexibility. If something comes up on the acquisition front, we can take advantage of that as well. We are in a number of data rooms and the Gulf of Mexico is certainly, in our opinion, still full of opportunity. That's the direction that we're headed.

Okay. Appreciate it thanks.

Sure.

Thank you. Our next question comes from the line of Noel Parks with Ladenburg Thalmann. Please go ahead.

Good morning.

Good morning, Noel.

Just had a couple things. My theory was right. The first one, just looking at the CapEx expectations for the rest of the year, are you expecting the drill bit CapEx to be relatively smooth -- for the rest of the year, or since you've already done six of your, or on approximately six of your 10 wells, assuming you keep with the current budget, would we see lower activity for the fourth quarter?

I don't think that that's necessarily true. Again, we have a huge amount of flexibility here, and as I look at it, that's not necessarily the case. We've certainly drilled or are drilling the majority of the announced, the previously announced 10 wells. However, we're also looking at other prospects that we could add before the end of the year. And I expect that we'll do that. I'm not going to warrant that to the market at this point, but it's kind of pointing in that direction. We're also seeing some, what I think are reasonable opportunities for acquisitions.

Okay.

So I can't really forecast to you exactly how that's going to come at the end of the year. It's a problem, but it's a quality problem, because we've maintained very good liquidity and the ability to move when it's appropriate to move is very important to us.

Sure. Could I get you to talk a little bit more about the Viosca Knoll well and just more about what you've learned about the structure that you have there.

Yes, what happened was we drilled a well that would in and of itself be noncommercial, but in so, in so doing, that particular well, we found some sand in another pay sand that was off structure, on the block that continued on to that block that we weren't really anticipating. As a result, we found another take point in a well that was already existing on the platform that will enable us to -- well, that enables us to capture those reserves. So while we won't complete this particular well, we've been able to do a recompletion, or we will be able to do another recompletion on a well that's a little bit further up structure there.

And ball park--

In fact, we've already done that. Production on that is about 5.5 million cubic feet a day and about 330 barrels of oil a day.

Great. And what's your working interest there?

Well, we own most of the block there. I'm sorry. It's 100%, yes. 100% on that block, so we'll get all of it.

Oh, great. And I guess my last one really was around the changes you made on the balance sheet, I think Danny commented that you did lower working capital during the quarter and also you talked a bit about the activity with the credit line to give you interest income to offset your swap. I understand you'll do the credit line movement again until the swap expires, but for the rest of the working capital it's going to be more or less steady state going forward, would you expect?

Yes.

Okay, great. That's it for me.

Okay. Thanks, Noel.

Thank you. (Operator Instructions) Our next question comes from the line of Biju Perincheril with Jefferies & Company. Please go ahead.

Hi, good morning.

Good morning Biju.

Couple of questions. Tracy, I think you've spoke in the past about maybe staffing up to look at potential onshore acquisition opportunities. Can you comment on where you stand with that now? And also, if you're looking at producing properties, do you see opportunities onshore that compete with offshore opportunities?

Yes, as far as acquiring production onshore, we've been in a number of data rooms. We're seeing onshore pricing really, in our opinion, very high in comparison to what we think we should, they should be at. I mean we're -- if the reserves aren't a big mystery to us, what we're seeing. People are just paying a lot for the reserves. And I understand that pretty well. I mean people still have to replace reserves. As far as onshore drilling prospects, we're seeing some really good stuff onshore to drill and we're getting ready to drill one of those prospects coming up here in June and expect to see more on that before the end of the year.

Okay, so if you look to expand onshore would it be more Gulf Coast area that you'll look at or any interest in moving more resource play type projects?

No. The short answer to that is, yes, it will be more Gulf Coast oriented onshore. I've not been terribly impressed with the economics that we've seen on the resource play so far.

Okay, and then the borrowing base you talked about, is that including the new acquisition, or--

I'm sorry?

The new -- the borrowing base that you talked about, $405 million, is that post the acquisition, or do you get any benefit from the reserves that you added there?

I'm sorry. I didn't hear the first part of your question. Maybe somebody else did. I'm--

It is after the acquisition.

Okay.

It's $405.5 million, including the acquisition.

Got it. Thank you.

Thank you, sir.

Thank you. And our next question comes from the line of Brian Kuzma with Weiss Multi-Strategy. Please go ahead.

Good morning, guys.

Good morning, Brian.

I was just curious, once you guys are drilling right now, what's your working interest in those wells? Is the Main Pass--

What's the working interest wells, what is the working interest in the current wells that we have right now?

That you're drilling right now. I think one was Main Pass 283. One was Main Pass 108.

Right. The Main Pass 108E-3 is 100% W&T. And The Main Pass 283A-6 is 88.5% W&T.

Okay. And then I just wanted to make sure I understood properly. At the beginning you guys were talking a little bit about I think some tax proceeds you were planning on getting later on in the year. I couldn't tell if they were tax or insurance proceeds. I just wanted to make sure I got that clarified. I think it's $78 million number.

Brian, that's tax. Again, we filed for a refund claim with the IRS. We expect to receive $9.1 million in the second quarter and $78.3 million in the fourth quarter. The $78.3 million all relates to NOL carry-backs that will, again, result in the refund claim.

Got it. That makes sense. In terms of insurance recoverables, you still have some of those that you plan on receiving this year as well.

We do. If you'll remember at the end of the year, we had $30 million. We've since collected some of that. We've since added to that. It looks like about the same balance, but there's actually quite a bit of change going on and that again, we're adding to it and we're collecting, so all of that's going really well.

I got you. It's still $30 million. Okay, then you guys threw out some numbers for production adds from recompletions and work overs. Are those gross numbers or are those net numbers? It's like $34 million a day from recompletions and $9 million a day from work overs.

Those are net numbers.

Perfect, that's what I needed. Thanks, guys.

Thank you. (Operator Instructions) One moment please. Our next question comes from the line of Bruce Brewster with Brewster Asset Management. Please go ahead.

Hello.

Hello.

You seem to be not too concerned about the impact of the BP spill on your operations, except to say if the plumes spread and there were increased fumes, you would have to take that into account. But I'm having a hard time understanding what the worst case scenario is. I believe that government officials said that all new drilling in the Gulf of Mexico was going to be temporarily postponed and I don't know if that means drilling that's in progress now or that has been contemplated or permitted or what they were talking about in that case. And I also heard another government official say that if the equipment in place over the hole now should blow out, that the spill could go to 100,000 barrels a day, which I would think would make anything temporary quite permanent. Could you address what you feel the administration's attitude is?

Mr. Brewster, you're asking me to speculate on something that I can't possibly know.

Well, I'm asking--

So I'm just going to decline.

-- how your plans are going with respect to this.

Sir, I have addressed that in my statements previously. You're asking me to speculate with regard to what government officials may or may not do, and I can't possibly know that. Next question, please.

What -- can I ask --

Our next question comes from the line of Noel Parks. Please go ahead.

Hi. Just a couple more things. One of them, could you talk a little bit more about Daniel Boone and you talked about doing some more review there, and the issue you had with pressure, just what your options are going forward as far as further development there?

Yes, the options, Noel, are that, first of all, we need to assure ourselves of what we think has occurred here. We're not exactly certain. We don't know exactly whether this is a reservoir issue, whether this is an equipment issue. So we're still running the diagnostics on that. We're still trying to figure out what we think has, has or has not occurred in the reservoir. That could affect some of our up-dip reserves as well, depending upon how we look at it. So we're still trying to assess that, but please note that we've not included any of that production in our guidance going forward for the rest of the year.

Okay, great. And then just one more sort of housekeeping thing on the balance sheet, given the use of the credit line I was talking about before, come the end of the quarter, would we expect that you would have basically all positive cash flow would just get retained in cash, or would, would it go to pay down the revolver, I guess, to the extent that you could come -- from your end, just trying to figure out which bucket to put that in at the end of the quarter.

Noel, my preference would be to put the money back in the ground.

Okay. Good enough. Thanks.

Thank you.

And this concludes the question and answer session. Mr. Krohn, please proceed with any closing remarks.

That's about it for the day, folks. I really appreciate your attention and we'll talk to you next quarter, if not sooner. Thanks so much.

Ladies and gentlemen, this concludes the W&T Offshore first quarter 2010 earnings conference call. If you would like to listen to a replay of today's conference, please dial 303-590-3030, with the access code of 4285677. That number again is 303-590-3030 with the access code 4285677. Thank you for attending the conference. You may now disconnect.