W&T Offshore Inc (WTI) 2010 Q2 法說會逐字稿

Good day, ladies and gentlemen. Thank you for standing by. Welcome to the to W&T Offshore second 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 third of August, 2010. I would now like to turn the conference over to Janet Yang, Manager of Finance for W&T. 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 second quarter 2010 results.

Before I turn the call over, I have a few items to point out. 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 August 10, 2010. To use the replay feature, call 303-590-3030 and dial the pass code 432-9423.

Information recorded on this call speaks only as of today, August 3, 2010, and therefore time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our second 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. Glad you could make it today.

So, without further ado, with me today are Danny Gibbons, our CFO, Jeff Durant, our Senior VP of Exploration and Geosciences, and Steve Schroeder, our Chief Operating Officer. Also, Jamie Vazquez, our President, is going to be here for the Q&A session as well.

On the call, we're going to review some of the events that took place in the quarter; our objectives for the second half of 2010.

Suffice to say, we had a pretty good second quarter. Our production came in at the high side of our guidance, while we were below the mid-point on expenses. We also had a substantial amount of extra cash come to the door without-- which further strengthened our liquidity position. We received almost $100 million in proceeds from the US Treasury for tax-loss carrybacks and $23.5 million for the quarter, $32.5 million for the year-to-date period in insurance reimbursement as well.

Although commodity prices were down a bit on a sequential basis, we realized additional revenue due to a $20.1 million recoupment of royalties previously paid to the MMS, now known as the Bureau of Ocean Energy Management, Regulation, and Enforcement, or the BOEM, under the Deep Water Royalty Relief Act. Royalty relief recoupment is due to Kerr-McGee winning a settlement against the MMS in 2009, and of course, we purchased a lot of properties from Kerr-McGee in 2006.

Beginning on May 1, our revenue was also increased by the contribution of the two deep-water-producing fields we acquired from Total; specifically, the 100% working interest in Mississippi Canyon Block 243, known as Matterhorn, and a 64% working interest in Viosca Knoll Blocks 822 and 823, known as Virgo. As we stated in our last earnings call, the acquisition price was adjusted for the effective date of January 1, so the final transaction price was $116.6 million, which was paid in cash.

Now, please-- Steve is going to provide you with an update on these new operations later. But let me just say that we have seen better-than-expected well performance to date, and we're very pleased with the acquisition. Our mid-year third-party reserve analysis benefited from the addition of these newly acquired reserves, as well from positive well performance and a higher price environment. The analysis indicates that mid-year reserves are up 15% over year-end 2009 reserves. As we all know, higher prices allow us to reinstate some previously written-off reserves, and it can go the other way again if prices were to fall in the future. Regardless, we were really pleased to have a positive price revision, and increase in mid-year reserves from not only price, but because of acquisitions, the drill bit, and well performance.

Switch gears here a little bit. At the moment it's unclear what new regulations will be imposed on operations in the Gulf of Mexico. But with a vast majority of our acreage being located in the shallow waters, drillable with a jack-up rig versus a floating rig, we expect less impact on those operations from any new potential rigs. Also, with almost 80% of our acreage being held by production or HBP, we are not as concerned about lease explorations. We did have one deep water exploration well planned in our 2010 budget, which isn't going to happen this year.

As we've stated all year, we're pursuing onshore activities and opportunities more. So, our first onshore well, which was started in 2009, was successfully brought online in July 14, 2010. We've also begun drilling another well onshore in Louisiana. Further, we expect to spout a well in south Texas shortly and plan to drill other wells there this year also.

Jeff will provide the details shortly. We expect to continue to balance onshore and offshore drilling and acquisition opportunities that we believe will allow us to generate the best overall returns to all of our stakeholders.

Please note that we issued a press release yesterday announcing an increase in our quarterly dividend to $0.04 per share. We are pleased to be able to reward and thank our existing shareholder base for their continued support.

Now, before I turn this call over to Danny, I want to speak about our announcement that Reid Lea resigned his position as Executive Vice President and Manager of Corporate Development for W&T. Although we're going to miss Reid, we're all pleased that he will remain as a consultant, at least for the near future, to effect a smooth transition for our A&D team and help with deals of interest. I would just like to publicly thank Reid for all of his hard work and his many contributions to our growth and success over the past 11 years. We particularly appreciated his sacrifice during and since Hurricane Katrina, when he agreed to move to Houston while his family remained in New Orleans. I know his family is glad to see him return home.

Now, with that, I will turn it over to Danny to further explain the results of the second quarter. Danny?

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 will find our year-over-year comparisons of our quarterly financials in the earnings announcement we released this morning.

Revenues for the second quarter were $179.7 million. That's up from $169.6 million reported in the first quarter of this year. It's primarily due to the recoupment of $20.1 million of royalties previously paid to the BOEM under the Deep Water Royalty Relief Act, as well as the contribution of production from the Matterhorn and Virgo fields beginning on May 1. The higher volumes were partially offset by a lower average realized sale price of $7.87 per [Mcfe] in the second quarter, which is down from the $8.50 per [Mcfe] in the first quarter.

Production in the second quarter averaged $250.5 million a day, compared to $221.7 million a day in the first quarter of 2010. Production volumes associated with a royalty recoupment were $27.5 million per day.

We continue to be negatively impacted by the pipeline outages of both Main Pass 108 and East Cameron 321 during the second quarter. The East Cameron 321 field was shut down for only eight days, but Main Pass 108, with volumes of about $14 million a day, has been shut in since June 3, and in fact is still shut in. Regardless, we are pleased that second-quarter production came in at the high side of guidance, despite these third-party pipeline outages.

Also, I'd like to remind you that 46% of our production is from oil and natural gas liquids, so at current oil prices, it generates substantial cash. And with a ratio of almost 16 to one related to pricing, oil to gas, versus six to one related to volume, I thought you might find that important.

Our average realized sales price for the oil was up to $70.97 per barrel in the second quarter, from $69.95 per barrel in the first quarter of this year, while the average realized sales price for natural gas decreased to $4.47 per Mcf, from $5.38 per Mcf for the sequential periods.

Now, let me move on to the discussion of lease operating expense, or LOE. Just as reminder, internally we split LOE into five components-- base LOE, insurance premiums, workovers, facilities work, and hurricane remediation. (Inaudible) LOE was $52.5 million, or $2.30 per [Mcfe], in the second quarter, up from $35.4 million, or $1.77 per [Mcfe], in the first quarter. We added the operating cost of the two recently acquired deep-water platforms for two months of the quarter. And remember, the first quarter benefited from an adjustment to our estimated hurricane remediation costs and insurance reimbursements related to Hurricane Ike and various cleanup adjustments made to our [AFE] accruals.

Facility expenses are also up in the second quarter. It should be expected. This work, which includes [blast and paint], is usually done during the summer months when the weather is better and the daylight hours are longer.

DD&A is up substantially, but keep in mind that roughly $7.2 million of the $76 million is due to the production associated with the royalty relief recoupment. General administrative costs are also up due to higher employee and incentive compensation expenses, as well as the closing expenses associated with the Total transaction.

In addition, the first quarter benefited from a management fee of approximately $1 million related to one of the divestiture packages we did last year.

As it relates to financial performance, our reported net income in the second quarter of this year was $27.9 million, or $0.37 per share, versus net income of $42.3 million, or $0.57 per share, in the first quarter. Adjusted for unusual items for the same periods, net income was $16.1 million, or $0.22 per share, compared to $39 million, or $0.52 per share. The unusual items for the second quarter included royalty relief recoupment, net of DD&A expense, of $12.9 million, and unrealized derivative gain of $5.3 million.

Typically, we focus on adjusted EBITDA because the adjustments usually relate to non-cash items. But with the largest adjustment this quarter coming from the $20.1 million royalty recoupment, which is a cash item, we thought we should provide it both ways. EBITDA was $116.2 million in the second quarter, compared to $124.9 million in the first quarter, and adjusted EBITDA was $98.1 million in the second quarter, compared to $119.8 million in the first quarter. The lower amounts are due to both an increase in LOE and G&A, partially offset by higher revenues, as previously discussed.

Our cash balance at the end of June was $72.9 million, down a bit from $84.2 million we reported at the end of the first quarter. However, we were able to fund the net $116.6 million acquisition assets from the Total and other capital expenditures with cash on hand, cash flow from operations, and the cash from the US Treasury, without drawing under the revolver.

At the end of the quarter, we had the entire $405 million available under our revolving credit facility. Cash flow from operations for the first six months of 2010 was $244.3 million. Included in this amount is the royalty relief recoupment previously discussed, $6.2 million of which was monetized in the second quarter, with the remaining $13.8 million to be offset against future payments to the BOEM, all of which should be in the third quarter.

On the insurance receivable side insurance receivables are lower at the end of June compared to March, as we have been collecting on our claims from our insurance underwriters. The insurance receivable balance is down by $16 million, and ended the quarter at $13.8 million. In May and in June, we renewed our insurance coverage, which we are pleased to say provides a bit better coverage at a lower premium than last year. You will find the details of the coverage in our Form two, 10-Q, which we plan to file with the SEC in a day or so.

As Tracy mentioned, we received $99.7 million in tax-loss carrybacks from the US Treasury in the second quarter. We had expected to receive the bulk of this amount in the fourth quarter, but obviously we were pleased to have received it earlier.

Our effective tax rate for the quarter ended June was approximately 9.9%, and this is primarily due to a decrease in our valuation allowance for our deferred tax assets. Our forecast of taxable income for 2010 has allowed us to reduce a portion of our valuation allowance. We project our effective tax rate for the year of 2010 to be approximately 10.3%.

In regard to hedges, we did not make any additions to our hedge position during the quarter. But it is important to note that our interest rate swap will expire in August of this year. Hallelujah.

With that, I'll turn the call over to Jeff Durant. Jeff?

Thanks, Danny. And good morning.

Let me start with an update on our exploration and development drilling program. In the second quarter, we successfully drilled two exploration wells; the Main Pass 98 number one and Main Pass 279 A-6 sidetrack. Additionally, we continued to drill a third exploration well, the Main Pass 108 E-3, and are now drilling a well onshore in Louisiana.

As we mentioned in the last call, the Main Pass 98 number one found 55 feet of gas condensate and three sands. This well was drilled from an open-water location and requires the construction of facilities and installation of a flow line. We are currently constructing facilities, and hope to have this well online later this year. Following installation of our platform and facilities, an additional delineation development well could be drilled during the first half of 2011.

Our other second quarter success, the Main Pass 279 A-6 sidetrack, will drill from an existing platform, and we've been able to bring this production on right away.

This well encountered over 100 feet of oil and gas and four sands, and we've added reserves associated with this well during the second quarter. It began producing the third week of July, and is now producing over 773 barrels of oil per day, 0.8 million cubic feet of gas per day, for a total of 5.5 million cubic feet equivalent per day, all of which is net to W&T.

At Main Pass 108, we're currently drilling the 100% working interest E-3 well, and expect it to be at TD towards the end of August. Results to date on this well have been very encouraging. We have already encountered 135 feet of gas condensate and five sands, and we haven't even seen the well's main objective. The unrisked gross exploratory potential for this well is between 15 and 30 Bcfe. Similar to the A-6 sidetrack, we would be able to get this production online quickly, but we will have to wait on resolution of the Main Pass 108 pipeline outage that Steve will discuss shortly.

As I mentioned in the last call, we were planning to split an onshore well in the second quarter. In early July, we began drilling this Louisiana prospect, with a proposed TD in excess of 18,000 feet. We have a 50% working interest in this well as a non-operator. The unrisked gross exploratory potential in this well is between 60 and 100 Bcfe. This well is successful. We could expect to have production online as early as the end of the year. This prospect has potentially large reserves and competes favorably with our offshore projects on a full-cycle economics.

Also onshore in the third quarter, we will participate in another onshore well located in south Texas. We'll have a 50% working interest in the well as a non-operator. This well will be drilled to a proposed depth of about 14,000 feet, and has a gross unrisked exploratory potential of between 40 and 60 Bcfe. We are planning to drill other non-operating wells in south Texas this year.

With that, I will turn the call over to Steve Schroeder. Steve?

Thanks, Jeff.

For the first half of 2010, we drilled or were drilling a total of six wells, split between five exploration and one development well. Five of the six wells were successful, with only one well being non-commercial. Reserves at mid-year are up, with the wells we drilled, the acquisition from Total, and the benefit of higher prices.

The Total transition has gone very smoothly. We've hired some former Total employees, and they are fitting in very well. We've been pleased with the integration of the operations and have had some positive items, including some upward revisions, in the mid-year reserve analysis due to well performance and higher prices.

As Danny mentioned, we were impacted negatively in the second quarter by outages and pipelines we don't operate. These outages affected sales at Main Pass 108 and East Cameron 321 fields.

The pipeline outage that impacts the Main Pass 108 field will continue for the remainder of the third and into the fourth quarter of this year. Getting this production online, which is at least 14 million cubic feet equivalent per day, is a top priority. Accordingly, we are evaluating our options, which include purchasing a pipeline, rerouting the production, or even constructing a new pipeline.

Turning to our drilling plans for the remainder of 2010. We previously said we were going to drill ten wells this year, one of which was in the deep water. The deep-water well has been postponed, pending resolution of the drilling moratorium in the Gulf and the impact of new regulations on deep-water drilling.

Also in the last call, we said we would be drilling one onshore well and two conventional shelf wells during the balance of the year. As Tracy and Jeff mentioned, we have spud the onshore well in Louisiana, and we are now planning to drill other non-operated wells in south Texas.

Thus far in 2010, we have performed 15 re-completes that added net initial incremental production of approximately 25 million cubic feet equivalent per day at a cost of $14 million. We also did 12 workovers, for a cost of $12.9 million, that added net initial incremental production of approximately 10 million cubic feet equivalent per day. We plan to continue an active recompletion and workover program throughout 2010, and we have budgeted $20 million and $7.5 million respectively for this work for the remainder of 2010.

During the quarter, we continued to perform plug and abandonment activity on platforms damaged during Hurricane Ike, and for the second quarter we incurred $20.4 million performing such work. However, we received or expect to receive $28.4 million in insurance reimbursements related to the work we have done to these and other platforms covered under our insurance program. This work will continue for the remainder of this year and into next year. As it relates to this year's storm activity, we experienced very little impact on production from Hurricane Alex and Tropical Storm Bonnie in July.

Related to the current cost of goods and services, it looked like costs had bottomed out before the spill. Since the spill occurred, you can see further downward pressure on some equipment and services, due to the excess capacity. For other types of equipment, prices had been rising due to the demand by BP for the cleanup effort. Once that effort is reduced, we expect costs to return to pre-spill levels or even less.

Let me update you on production. We were on the high side of production guidance even before considering the royalty relief adjustment. We experienced better well performance than we anticipated, which offset the effect of all the various pipeline outages. Additionally, the royalty relief adjustment added over 2.5 Bcfe to production for the quarter, bringing total production reported to 251 million cubic feet equivalent per day.

In the third quarter of 2010, we will see an impact of productions from our 2010 drilling program, our work programs at Main Pass 283 and Viosca Knoll 734, and we will have a full quarter of production from Matterhorn and Virgo. The offset will be the natural reservoir decline and no production from Main Pass 108 field during the pipeline outages. We have also included five days of downtime for a potential hurricane into our production guidance number.

For the third quarter, we anticipate crude oil and natural gas liquids production of between 1.4 million and 1.8 million barrels, and natural gas production to be between 8.8 and 10.8 [Bcf], and a total production to be in the range of 17.4 billion to 21.3 billion cubic feet of gas equivalent.

For all of 2010, we anticipate production to be between 6.-- we anticipate oil production to be between 6.1 million and 7.3 million barrels of oil and natural gas liquids, and between 38.4 billion and 46 billion cubic feet of natural gas, for a total of between 75 billion and 90 billion cubic feet of gas equivalent. You will note we have narrowed the range of our annual production guidance.

Relative to lease operating expenses, our guidance for LOE in the third quarter 2010 is in the range of $48 to $58 million, and between $172 million and $211 million for the full year of 2010, down from our prior full-year guidance of $177 to $216 million.

These estimates do not include allowance for hurricane-related expenses or insurance reimbursements. Like last quarter, our gathering transportation and production taxes for the third quarter of 2010 are expected to be between $4 million and $5 million, and between $18 million and $22 million for the full year, which is unchanged from our prior guidance.

Now let me turn it over to Tracy for closing remarks.

Thanks, Steve.

Out of our original $450 million budget, we've spent $206 million so far, and we've identified another $70 million for future projects this year. We still see good opportunities for the remainder of the year, plus we have our $405 million revolving credit facility fully available to us. We're focusing on acquisitions and joint ventures, both onshore and offshore.

Despite all of the turbulence, we're planning to remain pretty active in the Gulf of Mexico. No question, the oil spill was a tragedy. But I find it interesting that no one is talking about the dramatic flow rate of the Macondo well and its demonstration of the prolific nature of the reserve potential in the Gulf of Mexico. That kind of oil production isn't available in any other domestic place. I don't know of any other domestic (inaudible), certainly in the lower 48, that will flow up to 60,000 barrels a day.

As I've said over the years, turmoil and changes often create opportunity. We'll continue to look for the right opportunities and work to remain flexible, in order to be able to move quickly when it's appropriate. As always, our objective is to execute on the best opportunities available to us, and to generate high levels of cash flow.

Now, with that, we'll be glad to take your questions. Operator, please open the phone lines for Q&A.

Thank you. We will now being the question-and-answer session. (Operator Instructions) Our first question comes from the line of Neal Dingmann with Wunderlich Securities. Please go ahead.

Tracy, just wondering with the current offshore regulatory environment, does that change your plans as far as -- acquisition-wise for the next, oh, half-year to year as you look at potential deals?

Well, it certainly affects the way we think about some of the things we've looked at in the past. I don't know that it necessarily changes it. We are trying to figure out what the rules are going to be.

Okay. And then, any color as far as -- on some of these wells, obviously, it looks like the property from Total could be even a bit better than you initially thought when looking at permitting and some of these other things down the road. Are you getting any more clarity of the permitting issue, or just as far as wells that you can go after, or is it too early to tell?

It's a little bit early right now. The MMS is -- or, excuse me, the BOEMRE or BOEM -- I'm not quite sure how they refer to themselves. But the BOEM was split up into three divisions for administrative items, regulatory, and enforcement. Regulatory items, enforcement, and royalties. Of course, that's what they had before. The royalties are located in Denver. The other departments are located in New Orleans.

So, what they did was they changed the name of the entity, and maybe they changed some things within the organization itself. I'm sure they will. But I know that they are having their own issues with getting things straight about who is running what. I will tell you that, yes, that adds to uncertainty with regard to permitting. It doesn't kill it, but it certainly adds to the uncertainty.

Okay, great color. Thanks, Tracy.

Thank you. Our next question comes from the line of Steve Berman with Pritchard Capital Partners. Please go ahead.

Good morning, everyone. Question for Danny. Can you talk about the reasoning behind the $142 million and change drawdown on the revolver in July?

Steve, we know the interest rate swap, the reason I said hooray -- we incur interest on $142 million of an interest rate swap regardless whether it's -- any amount is outstanding. Historically, what we've tried to do is to draw on [that], invest it in generating interest income to try to mitigate, to some extent, the interest expense. That will stop here in a couple of days. The swap expires.

Okay. And question for anybody who wants to answer it. Can you talk about the onshore -- what formations you're targeting in Texas and Louisiana? It does sound like pretty prolific rates for onshore wells.

I would be happy to talk to you about it, but then I would have to kill you.

Oh. Can't have that.

There is definite competitive reasons why we don't want to talk about that, Steve.

Understood. I will get back in queue. Thank you.

Our next question comes from the line of John Freeman with Raymond James. Please go ahead.

Good morning. On the last quarter, on the original ten-well program that you had, you indicated that there was an unrisk potential of about 146 Bs. I'm just curious how much, if any, that number changes with basically the revised plan of sort of dropping the one deep water well that we are going to drill, and obviously you've had -- in some of these wells, you've had better success, I think, than what you originally thought. So, just wondering if that number has changed at all.

Well, the short answer to that question is yes, it's changed. I would expect that what you will see is a number about the same or slightly better.

Okay. And then on the mid-year reserve report of the increase of 15%, are you able to just sort of ballpark split it between how much of that was price related drill bit and acquisition?

Yes, I guess on that, price-related is about half of it. Everything else is the other half.

Okay. Great. Great quarter, guys. Thanks.

Thank you.

Our next question comes from the line of Richard Tullis from Capital One Southcoast. Please go ahead.

Thank you. Good morning.

Good morning, Richard.

Tracy, as you look at that US House bill that was -- drilling reform bill that was passed Friday, late Friday, where they rolled in the unlimited liability for economic damages, I mean, I don't know, it has a long way to go before it would ever become law. But how do you guys see that? I mean, would you continue to drill wells if that would become law with the unlimited liability on that side of things for damages?

Well, I think the short answer to that is yes. Depending upon what the bill ended up looking like, because we don't know that at this point in time. We don't know if the Senate is going to even vote on it at this point. There is some question as to whether they will or not on their version. But the version that the House passed, with the so-called unlimited liability, that's a kind of an interesting dilemma because it implies that we didn't have unlimited liability before. The reality is, is that you have liability to the extent that you are able to pay for it. And that's never changed, whether we have insurance or not.

So that's always been a risk factor for the Company, that, gee, you could have an incident that could be a substantial risk for you. The reality is, is that we've drilled in the Gulf of Mexico -- over 60,000 wells in the Gulf of Mexico and we had one incident like this. And I would tell you that certainly there was negligence involved. Whether it was gross negligence or not, I will let other people decide that, because I don't have all the facts. But I would tell you that if the intent is to -- Congress generally overreacts to issues that are of present concern. And I think politicians in general overreact to things.

I would hope that this industry will have the time and the opportunity to show them exactly what is important and how it works and things that do need to be changed. I don't really think it's that much. I will use the analogy of an airplane falling down. When a plane falls down, most of the time it's pilot error. Sometimes you will have an equipment failure, which is more rare. But most of the time it's pilot error. We don't ground every plane in the United States as result of that. But yet, in the Gulf of Mexico, the immediate outcry was to stop everything and punish the industry. The emphasis seems to be more on fixing the blame than fixing the problem. I think I've said enough about that.

Sure. And how does that generally work? You have a financial responsibility provision already. And I guess they are talking about bumping that up. So, if you meet that financial or responsibility provision, you can go forward drilling wells if you assume or can insure the unlimited liability piece of it?

Well, you can't insure unlimited liability. Let me --

Yes, of course, of course.

That's not possible.

Right.

You can insure a liability, at a price, usually, if you've got enough capacity in the market. The way that the [open 90] rules were structured were that you were -- as an operator, you were required to have a certain level of financial responsibility. And that was a minimum of $35 million when it was first written. In addition to that, there was an oil spill liability fund that was funded through an $0.08 per barrel tax on oil over a long period of time. When it got to $1 billion, it stopped funding.

Of course, it's a bit of a misnomer. It's not really a fund. It's kind of like Social Security in that yes, you pay into this fund, but it's not sitting in an account somewhere. To be sure, Congress takes that money and they spend it elsewhere in the general fund. So, it's a bit of a misnomer for anybody to say that there is a -- an oil spill liability fund sitting around waiting to be called upon. It's not that way at all. And of course, part of the CLEAR Act that was passed by Congress is calling for an increase in those taxes, on a per-barrel basis, to fund yet another fund that won't be available to act on. So, it's just another tax. And it's another way for politicians to indicate that they done something that's meaningful that actually has no value.

Okay. Well, that's all for me right now. I will jump back in the queue. Thank you.

Sure.

Our next question comes from the line of Jeff Robertson with Barclays Capital. Please go ahead.

Thanks. Tracy, can you talk a little bit about your strategy for the onshore activity, and in particular, what the follow-ups might be to the couple of wells that you are drilling, and then the approach going forward between non-op, and perhaps, generating prospects?

Sure. Right now, Jeff, we're looking at mostly conventional stuff that has a little higher impact for us. So that has interest to us. We're still not what I would call a shale player. We are certainly looking at formations that we think -- we got a pretty good idea of what kind of deliverability and things we are going to have. So, expect to see some more of that. As to whether we would be operator or not, that's not really an issue. We can certainly be the operator or not. It just so happens that things we are looking at -- it's been easier for us to participate as a non-operator. If we get into an area and it looks like we've got some acreage of size and interest, then we will change that tactic a little bit.

All right. I assume, since you are south Louisiana and gulf coast of Texas, you are basically looking at similar geology to what you all have done in the Gulf of Mexico'.

A lot of it is along the gulf coast onshore, but no, not necessarily. We are looking in some other areas at this point in time.

Okay. Thank you.

Thank you, sir.

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

Good morning.

Good morning, Noel.

Just a couple things. You had a couple wells you reported -- I think one of them actually you had mentioned last quarter, but -- where you had some nice pay. And, just trying to get a sense of -- for the things that you drilled in the most recent quarter, can you give us a sense of sort of what point over, say, the past year or so or -- you had some slowdown activity, maybe these particular prospects were high graded or prioritized? Just trying to get a sense of whether you've got a long series of wells like the ones that were successful this quarter on deck, or were they more sort of special circumstances?

I'm sorry, Noel. I'm having a hard time hearing you. Would you repeat the question, please?

Sure. Just -- for the wells that were successful this quarter, I was wondering sort of what vintage they were, as far as, over the past year, you slowed activity a lot and did some high grading of your various prospects. So just sort of wondering when these came on to the list.

Are you asking for geologic age of these wells? Is that what you're asking?

No, no. Just within your own queue -- your own queue of drilling prospects.

I think more or less we are focused on oil, Noel. That's kind of what the economics dictates. And so, that's kind of what we are looking at mostly.

Okay. And similarly, as far as workovers and recompletions. Can you give us a sense of what that inventory looks like, maybe heading into next year? And just how much of a dent that might be able to make in the -- your overall decline rate, these relatively low risk, high-reward activities?

Now, we are working on that budget now. But I expect you will see a pretty high level of activity on workovers and recompletes. I know we have some work to do with the properties at Virgo and Matterhorn, as well. Maybe even a side track there a little bit later on. Of course, we are not allowed to do that side track at this point in time, due to the moratorium. But we are planning on potentially doing that if one of our workovers isn't successful -- or recompletes, rather, isn't successful.

Okay. Great. That's it for me. Sure.

Thank you. Our next question comes from the line of Richard Tullis with Capital One Southcoast. Please go ahead.

Yes, just a follow-up. How much production from -- related to the royalty relief, is added into second half 2010 production, if any?

2.5 BCF.

2.5 Bs. Sorry?

Second half, we have nothing budgeted. We have (inaudible) 130, so it would be zero. So I can't think of anything.

The answer is we have 2.5 BCF out of the deep water royalty relief, and we don't have anything scheduled to come on the books after that.

Okay. And then, just to clarify on the revolver drawdown, $142 million. You have that in cash or cash equivalent right now?

We do. We have it invested. Again, the concept is to invest -- is to generate interest income to try to offset the interest expense that we are incurring otherwise from the interest rate swap.

Okay.

Yes, it's just a simple arbitrage on the swap itself.

Okay.

Again, that expires here in a few days.

Okay. Well, that's all I have. Thank you.

Thank you, sir.

Thank you. That concludes the question-and-answer session. Mr. Krohn, please proceed.

Thank you very much. We will talk to you again next quarter, if not sooner.

Ladies and gentlemen, this concludes W&T Offshore's second quarter 2010 earnings conference call. If you would like to listen to a replay via the phone for this conference, please dial 303-590-3030 with the access code 432-9423. ACT would like to thank you for your participation. You may now disconnect.