VAALCO Energy, Inc. (EGY) Q1 2012 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. Welcome to the First Quarter 2012 Earnings Report. [Operator Instructions] As a reminder the conference is being recorded. I would like to turn the conference over to CEO and Chairman, Robert Gerry. Please go ahead.

Thank you, John, and good morning, ladies and gentlemen, and welcome to VAALCO’s first quarter investment conference call. As always please bear with me while I read through our Safe Harbor Statement. This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21 of the Securities Exchange Act of 1934, as amended. Forward-looking statements are those concerning VAALCO's plans, expectations, and objectives for future drilling, completion, and other operations and activities. All statements included in this presentation that address activities, events or developments that VAALCO expects, believes, or anticipates will or may occur in the future are forward-looking statements. These statements include expected capital expenditure, prospect evaluations, negotiations with governments and third party and reserve growth. Investors are cautioned that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. These risks are further described in VAALCO's Annual Report on Form 10-K for the year ended December 31, 2011 and other reports filed with the SEC, which we can be reviewed at www.sec.gov. I am joined today in the office by Greg Hullinger, our CFO, and on the telephone from Gabon is Russell Scheirman, our President and Chief Operating Officer. I will turn the meeting over here to Greg briefly in a moment, but let me give you a quick overview since I am sure a lot of it's on your minds and it has do obviously with Angola. I can’t cover a great number of details about it, but suffice it to say that we are going to Angola at the end of this month to clarify really with Sonangol our respected positions on Block 5 and hopefully shortly thereafter we will have a news release or positive news that we can report to you about. It appears that we have very interested parties, notice the plurals, circling around our data room and I will reiterate my opinion that I think within a few months we will have a 40% partner. We will get in to the details a little later after Russell’s report about what VAALCO has proposed, but -- so bear with me. And with that I will turn it over to Greg. Greg?

Thank you, Bobby. Good morning, everyone, and thank you for joining our call. I will take through the brief summary of our financials for the quarter. Starting out our net income for the quarter was $9.0 million this translates to $0.15 per diluted share that compares to a year ago at $11.2 million or $0.19 a diluted share. We take a look at revenues. Revenues were $45.3 million in the most recent quarter nearly identical to a year ago period at $46.8 million; key difference is that in the volume of crude that we sold however during the quarter. In the first quarter of this year, we sold approximately 388,000 net barrels of oil equivalent and that came from 2 liftings in Gabon. That compares to a higher volume sold a year ago at nearly 451,000 barrels and was based off 3 crude liftings. Our pricing was very strong. On a barrel of oil equivalent basis, our pricing for the first quarter was $116.59 compared to $103.76 in the first quarter a year ago. Again that's on a barrel of oil equivalent, we have taken the value of our gas that we produced domestically and of course that reduces that price. If we look solely at the value of the crude, the crude pricing that we sold it was $121.54 versus $104.09 a year ago, a real strong pricing. And what we saw was that the earnings, revenues were about the same but that was on the basis of a 14% reduced volume and a price increase on oil of about 17%. Looking a little deeper into the revenues. Our revenues for the first quarter this year does include a $3.1 million positive improvement resulting from a change in royalty percentage with the Republic of Gabon. Essentially what happened is the Republic of Gabon in a negotiation with not only ourselves but other producers in the country want to establish royalty on a fixed rate basis. We have been paying royalty at our production levels at 15% for a very long time. Under the new arrangement with the government we are going to be paying 13% royalty and it doesn't vary based on our production levels. The arrangement was retroactive to July 1st of last year, and that lowered royalty percentage resulted in $3.1 million of additional revenue. Of course offsetting that, you are going to see a big impact, the fact when you add the revenue in, and it turns into profit oil then it gets taxation and so we give up about half of that back to the Republic in the form of higher taxes. The royalty rate reduction actually does have a positive NPV over the remaining life of the contract. Essentially we would have benefited from lower royalty rates when our production declined to lower levels. But at our current production levels and expectations of paying 13% royalty again is a positive NPV event. And so, we see the impact of that in our first quarter financials. Our crude oil production for the first quarter averaged 21,100 barrels of oil per day. This is from Gabon. That's on a gross basis about 5,200 barrels net to VAALCO. That's down a little bit from a year ago, where we were at 23,200 barrels of oil per day or about 5,700 barrels net to VAALCO. And the basis for the decline is really just the -- is our normal production decline, which you see increasing cuts of water, and the way that we arrest that is with additional drilling. And Russ in a few minutes here will give you an update on our drilling plans that are going to take place in Gabon later this year. If I move to expenses, our operating expenses were very comparable year-on-year $5.5 million compared to $5.2 million, slight increase. There is a small impact on the fact that we capitalized some of the production costs associated with inventory. And we had more crude oil inventory at the end of the first quarter, again because we had 2 liftings instead of 3 during that quarter. And then, the resulting overall increase in OpEx is really due to that refinery subsidy that we're required to pay to Gabon, that was a net increase year-on-year of $0.50 million. Exploration expense, not a lot of it going on at the moment, we incurred $0.9 million in the first quarter of this year. That includes about $0.4 million that we spent onshore Gabon for seismic reprocessing and that's getting us in shape to drill our onshore well later this year also. We also spent about $300,000 offshore Gabon on our seismic acquisition in the seismic -- in the shallower waters. A year ago, we spent $1.1 million in the first quarter on exploration expense, so a very comparable number. Depletion, depreciation and amortization were lower in the first 3 months of this year at $5.0 million, compared to $6.1 million a year ago, and that's totally on the basis of lower sales volumes. Our G&A expenses were very comparable $3.5 million versus $3 million and the majority of that difference is associated with a overhead reimbursement that is associated with our Gabon operations. Essentially, the more we spend there we get more of an entitlement to take our G&A cost and actually charge it to the venture. That was a decrease of $300,000 year-on-year. Income taxes for the quarter amounted to $19.8 million, compared to $18.3 million for the same period a year ago. And inside of there again is the tax impact of the royalty reduction. So we had $3.1 million of increased revenues. However, right at 1/2 of that amount was taken away in form of additional tax we paid to the government. Moving from there, CapEx during the quarter we invested $16.9 million in CapEx, $8.8 million of it was associated with our second well in the Granite Wash formation in Texas. We spent $5 million on an exploration well in the Poplar Dome Field in Montana. And we spent additional $3.1 million on our Gabon infrastructure, and primarily this is the completion of our expansion work on the platforms to accommodate additional development wells. Over the course of the remainder of the year, we expect to spend about an additional $40 million for a total of $57 million CapEx for the year is our projection at the moment, which does not include an Angola well, which we are still optimistic that we will move forward on. Switching to the balance sheet for a moment, our cash at the end of the first quarter unrestricted was at $140 million compared to $137 million at the end of last year. So we are in great shape on cash and actually we have got quite a bit of our receivables that are turning into cash or already have in the second quarter. If you pay attention to our balance sheet you see that our accounts with partners is up substantially during the quarter from our year-end position. This has a lot to do with just the timing of when we cash calls for some of the expenditures that we have already monetized a great deal of that or has been billed to our partners to be paid in the next cycle. In our other receivables, quite a bit of increase there and that actually is the royalty receivable from Gabon and that's the royalty adjustment I already talked about. We are in control of our royalty payments and we actually monetized that already in the month of April, so it's in the second quarter. Our crude oil inventory is at $1.8 million compared to about $800,000 at year-end and that reflects a higher amount of crude that we have sitting in the FPSO at the end of the quarter. And looking ahead into the second quarter, you may recall from Russ explaining the lifting with our purchaser, but there is a balancing feature in both June and December, where the purchaser is required to lift enough volume to take it to the minimum stock level that we maintain. So essentially we had 2 liftings in the first quarter and we are essentially guaranteed 4 liftings in the second quarter. For instance, right now we have got a little over 400,000 barrels sitting in the FPSO. With production through the rest of the month, we will have about 900,000 barrels. And so we will see a lifting at the end of this month and then contractually we will see another lifting by the end of June. So we are going to see strong volumes in the second quarter. Okay. With that I think that's the financial highlights. So let me turn it over to Russ to provide an operations update.

Thanks Greg, and I just like to spend a few minutes reviewing our offshore Gabon projects at Etame, our onshore Gabon drilling plans, the results of our second Granite Wash well in Texas and the current testing plan for our new well on the Poplar Dome in Montana, the future Bakken/Three Forks drilling plans. Since it's only been a couple of months that we had a conference call, many of the planned activities described then have not yet commenced. But I will be sure to update you on those areas where activity has occurred. In Gabon offshore at Etame, we continue to maintain production rates of 20,500 to 21,000 barrels per day, with good performance from all 3 fields. We had some scheduled maintenance during the second quarter that will reduce volumes slightly in that quarter but it is on the order of less than a 1,000 barrels a day. As I mentioned last quarter, we completed the platform modifications to accommodate the new wells at both South Tchibala, Avouma, and on the Ebouri platform. We have also completed performing electrical upgrades and modifications to power up the new wells as they come on stream and we will be adding a new generator to each of 2 platforms. And the combination unit expansion is going to occur in Avouma here in the next month or so, due to the need for additional personnel to accommodate the new well that we are going to be drilling. And that will be followed by the addition of a produced water separation system also at Avouma, South Tchibala, which has the ability to reduce the amount of water that we currently have to send to the FPSO, and this will allow room for additional oil production when the drilling program commences. We are currently pretty much maxing out the FPSO in terms of fluid. We are sending it just north of 30,000 barrels total fluids a day. So even if we could pull the wells a little harder there is just no room in the FPSO until we get this produced water system in place to knockout probably 6,000 to 7,000 barrels of water we were sending over from Avouma. Our floor well drilling program offshore Gabon is firmed up to the second half of 2012. We will begin using these in the 350 foot click jack up rig the KC Deutag Ben Rinnes. We start the program with an exploration title hole at Ebouri in a new fault block. This has the potential to add reserves to the Etame complex this year about $7 million gross from Mutamba, which is $1.7 million net to VAALCO. In the most likely case if the well is successful an additional 1 million barrels or about 0.25 million barrels net to VAALCO is possible in the deeper Dentale which will be also be tested if Mutamba is successful. In the Ebouri pilot hole success case we will complete 1 well in the new fault block and then we will drill a second Ebouri well into the main field fault block. If the pilot well is unsuccessful, we still have room for an additional second Ebouri development well in the main fault block, so we are going to have 2 new wells to Ebouri out of this upcoming drilling program. At South Tchibala Avouma we are planning a developing well in the Avouma fault block, which will improve recovery from that portion of the field and allow us to capture reserves we are currently carrying is proved undeveloped. We also need to perform a work over at Avouma -2H on the Avouma -2H well, which is the best well in the field. This well had a failure in 1 of 2 ESPs that we had in the well and we are currently running well on the second ESP. So there was no loss of production as a result of the failure of the ESP, but we are down to 1 ESP. And our philosophy is that after the first submersible pump fails the first opportunity we have to change them both out so we have redundancy, we take that opportunity and that we do with this upcoming program. We have 2 optional swaps with Ben Rinnes and, as I said last time, there may be a second work over if we have any additional ESP failures. We also have the shallow water seismic lead that we shot last November, which we call the N lead prospects. It could cover contained over 50 million barrels of recoverable reserves and we should have the seismic process early in the first quarter of next year, which will give us time we think to mature the prospect and get it drilled in 2013. Moving to some new platform activity, I mentioned last time we completed studies for new platform at Etame and we are actively underway designing that platform. The Dermin [ph] Engineering is our contract engineer. The platform will be installed in late 2013, with drilling in 2014. We expect 3 initial wells and perhaps as many as 5 of this platform over its life. We are also finalizing our recommendation to our partners for a fourth platform. This will be in the area of the Southeast Etame discovery and North Tchibala Field. The North Tchibala Field is a Dentale Field and we are excited about the potential to be able to test a Dentale field alongside having the Southeast Etame Gamba field as a backup. The North Tchibala field also has a gas resource, which could be quite valuable later in the field life when we run short on gas that comes with the oil. Each of these 2 platforms represents about a $32 million net investment for VAALCO plus the cost at wells, which run about $7.5 million each net to VAALCO. Our goal in these 2 projects is to maintain our production near or above 20,000 barrel per day into 2016 from the Etame complex. Moving onshore to Mutamba, we've agreed a target with our partner Total. We are negotiating for the rig. We expect to have the prospect drilled this summer. It's a 10 million to 20 million barrel Gamba prospect in which we have a 50% working interest. And I have said before it is close to the Atora field, which is the Total operating field onshore that we could tieback to if we are successful so production could occur quite soon after we drill the well. Bobby mentioned Angola, and I think he has a few more words to say about that. So I am going to go ahead and move to our domestic activities. In the Granite Wash in North Texas, we completed our second well in Hemphill County with the 14 stage frac job on a 4,000 plus horizontal lateral. The well is slowing on a 26/64 choke and stabilized rate of 3 million cubic feet a day of about 50 barrels of condensate per day. We are limited by the line capacity into our purchaser Eagle Rock into their low pressure system. They are having problems with their high pressure system and we can’t get into it. So we are having to produce into their low pressure system. So we did not go for any sort of maximum rate on this well, but we’re just holding it at this 3 million a day and has been flowing like that since we completed it back in late March. In Montana at the Poplar Dome, we just completed a vertical well. We went through the Bakken/Three Forks, the Nisku, the Red River and Winnipeg. We successfully cored the Middle Bakken, the Nisku and a portion of the Three Forks, and based on log analysis, we think we have potential pay in the Nisku, the Red River and the Winnipeg side of the normal play executed in the Bakken/Three Forks. So we are going to be perforating those zones in order. We will start with the deepest, which is the Winnipeg. The Winnipeg is also the tightest. We shot that zone last week and to date the results have been inconclusive. We need to break it down and see whether it will produce; if it doesn’t we’ll move up to the Red River where the porosities and permeabilities are better, and then if that doesn’t work we obviously have the Nisku, which we have seen it on the core and its highly fractured and it's got a lot of oil in it. So we're confident that one of these zones we will make a completion out of, but we have to tell you later after we finish doing these tests. For the rest of 2012, we expect to pick up a rig sometime in the next 30 days or so and drill 2 new wells at Poplar Dome, one of which will be a Bakken/Three Forks test and then depending on the results of that, we will drill a second well, we're debating either vertical or horizontal. We will just have to see how the first well goes. We are also planning 2 Bakken wells in our Salt Lake area, which is also in Montana, near the Canadian border. We have about 6,000 acres there and we expect we will be drilling in offset locations to another operator; we've made good wells and we think that these will be exciting wells for us. So with that I’m going to turn it back to you Bobby.

Thank you, Russell. I think those of you on the call we will note that it’s going to be a busy year for VAALCO. It is shaping up that we will drill probably 10 development/exploration wells, basically 5 in this county and 5, perhaps 6 in Gabon. Back to Angola for a moment, we or I at least have suggested that VAALCO would drill a 100% 1 well to the post-salt in Angola to hold that concession. What we need from Angola is a 2-year extension that will enable us to get a partner to be able to drill to the pre-salt. The well that VAALCO is planning to drill would probably cost VAALCO around $35 million. Again it’s a post-salt well, but I reiterate to everyone that VAALCO basically took this concession as a post-salt prospect, and there is nothing wrong with the post-salt. We estimate and Sonangol confirms there could be 300 million barrels in the post-salt and VAALCO could do very well with that if that occurs. So we are excited about the post-salt. Obviously, with cobalt discovery in the Kwanza basin, the pre-salt is now in play. This is what VAALCO is searching for with a partner. We do have companies that are very interested in picking up the 40% that our Norwegian partners turn back to Sonangol. We hope that we will have an announcement within next few months that we have obtained a 40% partner and then we will go drill the pre-salt. Again we have 1,400,000 acres in the Kwanza basin which industry thinks now it probably the hottest basin certainly in West Africa with the cobalt discovery. There is going to be a lot of activity. VAALCO is in a good position and it could be a huge company maker for us if we are successful there. We have not given up on West Africa. We are looking at least 1 deal in another West African country. The reason I mentioned before that we come to the United States is that we were finding ourselves getting priced out of West Africa. But we tried to shoehorn our way into available situations and one has come our way. And with a little bit of skill and luck I think that we might have another country that we can explore in. So we will see how that goes. As far as the domestic prospects that we have Poplar Dome, as Russell very well described, is going to occupy a fair amount of our time. We've opened up an office in Denver. We did this about 3 weeks ago. We have 3 professionals up there now. It is designed really to look for other opportunities in the Rocky Mountains per se. We're focusing that on the Bakken/Three Forks again. And there are a number of opportunities that have been presented to VAALCO that we're sorting through. We are also looking at a few other potential unconventional plays that our experts now in Denver are investigating. I think it's fair to say that VAALCO is going to remain fairly conservative on acreage costs in some of these unconventional plays. We've done a fair amount of study of economics et cetera, et cetera, and we don't want to overpay for acreage. We do not want to overpay for drilling obligations that some of our peer groups are running into some trouble with. But the Bakken is probably along with the Eagle Ford the hot plays in North America's unconventional plays and I think we're well situated there. We don't have a continuous drilling obligation on Poplar Dome. One hold sold 22,000 acres. So we can take our time developing it. As Russell mentioned, we do have 3 obligatory wells that VAALCO is paying 100% on. We've drilled the first one. We have to drill the other 2 before year-end this year. But we're equipped to do that. We certainly got plenty of cash to finalize that program and then we'll probably commence on a scheduled horizontal drilling program on Poplar Dome. It's exciting that we've located 3 other reservoirs that are deeper than the Bakken/Three Forks. And as Russell mentioned, there is the Winnipeg, which looks a little tight, above that the Three Forks, excuse me, the Red River and above that the Nisku. So the Nisku looks terrific and we may have good information and a good report here in the next month or so on that prospect. But having said all that I think I'll open it up to questions. So John, why don't you take over?

[Operator Instructions] And our first question will come from the line of Steve Berman from Pritchard Capital Partners.

Let me start with a couple for Greg. How much of the $40 million remaining CapEx for the year is budgeted for Etame?

I would say, Steve, well quite a bit of it is. Our share of that with a great schedule coming up we've got half of the 6H well we expect to spend, as well as finishing up on our pipeline modifications, FPSO modifications, some platform design construction work. I mean I can tally it up real quick but it looks like about $12 million of it is associated there. The majority of that remaining $40 million is really with the Montana Wells.

Okay. And you gave actual numbers net and gross for Q1 sales-wise. But can you -- could you give -- I got my calculation off of the liftings which ended up being a little too low, so maybe this has to do with the royalties you talked about before quick. Can you just give me the percentage of the gross volumes that should be met with VAALCO as we move forward here? It's been around 24% but what's the right number now?

Well, you have to probably do look at our calculation, Steve, and I can follow-up with you but it's probably a little bit higher than that.

Okay, yes. You mean talk about that offline?

But essentially we've got high taxation still in quarter 2 and quarter 3 of this year before we start our capital investing, which will then allow the cost account to takeover where we don't pay the taxes. So all that comes into the formula for determining the number of barrels we end up with.

Okay. And then a question for probably Russ, in terms of, if you go it alone in Angola, do you have a rig lined up for that or how does that stand right now?

We haven't signed up a rig yet. We've got the words out there, we're looking. And we think and Russell stop me if I'm wrong, we think we can get a rig to certainly drill for post-salt. Is that right Russell?

That's right.

Now we will go to the line of Kim Pacanovsky with MLV & Company.

I guess I'm wondering -- I know you don't have any lease issues in Montana. But if the 3 -- if your 3 first wells are all successful behind your wildest dreams, what do you envision the program looking like in 2013 in Montana?

If they're successful beyond our wildest imagination we will keep drilling. I think it's fair to say probably we have around 50 locations that we could drill. I think that's being very optimistic. But we could be there for certainly 3 or 4 or more years if it's wildly successful. And again, if the Nisku or the Red River, or even the Winnipeg, is productive that sets up additional reserves at VAALCO.

Right, right.

But it's too early to comment really on what we think about that.

Okay. Then the 2 Bakken wells, you said that you're drilling in Salt Lake, you mentioned there is another operator up there that has seen some success. Can you just give us some idea what those wells look like?

Yes, the other operator is called Taqa, T-A-Q-A; Taqa is down at the UAE. I think they've drilled about 10 wells. I think that the production probably and I'm guessing at this, but probably average is IPs around 400 barrels a day, I could be a little off one way or the other on that, but they're good wells. So I think some are obviously like always on conventional plays better than others, but appears the ones closest to us are their best wells.

And those are Middle Bakken wells?

Middle Bakken wells.

Okay. And I guess the $35 million on the post-salt well in Angola that's to the eight-eighths correct?

That's what?

That to the eight-eighths, $35 million?

That's correct.

Okay. So I'm -- I guess I'm just trying to figure out what a maximum, because you already have some, you have spending identified with projects, the infrastructure projects and wells that you kind of already slated to drill in 2013. I'm just wondering what a maximum budget would be for 2013 should you not have a partner, should you ramp up Montana, and then with everything else you've already identified?

It would probably run close to $100 million.

And now we will go to the line of Pascal Menges with Lombard.

I have a few questions on Angola if I may. The first one is how long can you wait for the Angolan administration to come back to you with a decision for you to be able to drill that well? I mean if you, let’s say if you don't have the decision before July does it means that you will not be able to drill that well because I understand that this license has an expiration date of November 2012? And then the other question is regarding the 40% assignment for the third-party. Will that come with a potential extension of the license or so or not?

Go ahead, Russell.

Yes, that's the intent. As Bobby said, you can't get too specific but we're talking to the Angolan authorities on a routine basis. We meet with our Block Chairman every week. We have a proposal in front of them in writing. They had given indication that it makes sense to them. They are running it through their system. I think for sure we would be able to drill a well of 100% and move on if we wanted to. The issue is getting the extension so that we can buy the deep-water seismic and have a better chance of attracting a partner for the pre-salt well.

You went to ground doing some of that?

Angola has indicated to us a favorable response to the letter. I think that probably they will allow us to commence drilling that well this year even up to the exploration date and perhaps if we show them rig is on the way, etc, etc, they will even give us an extension to drill that well this year.

If I may have a follow up question, if I understand well your answers, it will be the most likely attraction for the third party will be to have a seismic shot on the deep water something that I understand you don’t have to do. What would be cost of that seismic? How long would it take to conduct the survey and process the data? And can that be done before the expiry date?

The seismic has already been shot. They have a proprietary database that Sonangol owns, and we have to negotiate to buy it from them. And we've given our indication and we'll talk to them about that. We can't go into specifics on exactly how much it would cost because it's negotiable.

And then once we acquire the seismic we would have to do reprocessing which would take about a year, isn’t that right, Russ?

Yes.

Just bear in mind, we do have a pre-salt prospect and we could drill that today after --

Is it drillable as of today?

I beg your pardon?

Is it drillable with the knowledge you have as of today?

Yes, it's drillable and it's actually approved for drilling by the government.

And now, we will go to the line of Brad Heffern with RBC Capital Markets.

I just wanted to check in on the Granite Wash. With this new well result that you guys have, what are your plans for it going forward? Is it going to be wait to drill the remaining handful of locations there until gas prices recover?

We're going to keep that in reserve. We are not going to drill another Granite Wash with prices where they are right now. We don’t have a lot of acreage. I think we've got a total of a thousand acres roughly in the Granite Wash. And I think we probably drilled our last Granite Wash well and conceivably we might put it up for sale here in the next year or so, but we're going to move back and concentrate primarily on the Bakken.

Okay great. And then --

Sorry, our leases are paid up and don’t expire until the end of -- or sometime late 2014. So we've got a couple of years on it.

And then going back to a previous question, for the quarter it seems like the gross sales there also were implied even the new royalty rate roller higher than what they're looking for. Do you have the gross barrels that were sold? And is there anything funny with the royalty adjustment or anything like that would make the net barrels a little higher than the [indiscernible] would imply this quarter?

Well the net barrels would be, and I think it's going back to Steve's question, the net barrels would probably be around 25% rather than 24% which is what we're used to seeing on a revenue basis. And that’s because we pay 13% royalty, so will pick up 2% there from the 15% we used to pay but now we're having that 2% unless the cost account happens to full. If we cost account is empty that 2% flips over into profit oil's account and is taxed a little over 50%. So we pick up a net 1% on top of our net 24%, it puts us at about 25% now.

Okay, right got it. But that the royalty adjustment wasn’t included in barrels or anything like. It was attached to that, correct?

I think that’s correct.

[Operator Instructions]. And there are no more question in the phone line.

Okay. Well thank you all very much and we will see you at the end of the next quarter. I appreciate your attendance and look forward to the next quarter. Thank you all, bye.

And ladies and gentlemen, that does conclude your conference for today. Thank you for your participation and using the AT&T Executive Teleconference. You may now disconnect.