VAALCO Energy Inc (EGY) 2012 Q4 法說會逐字稿

Ladies and gentlemen, we'd like to thank you for standing by. And welcome to the end-of-the-year 2012 earnings report teleconference call. At this time, all participants are in a listen-only mode. Later, we'll conduct a question-and-answer session with instructions being given at that time. (Operator Instructions). As a reminder, today's conference call is being recorded.

I would now like to turn the conference over to your host and your facilitator, as well as the Chairman of the Board and CEO, Mr. Robert L. Gerry. Please go ahead, sir.

Thank you, Stephen, and good morning, ladies and gentlemen. And welcome to VAALCO Energy's 2012 and fourth-quarter conference call. Joining me today is Russell Scheirman, our President and Chief Operating Officer, and Greg Hullinger, VAALCO's Chief Financial Officer.

Please bear with me for a minute while I read our Safe Harbor statement. This conference call includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 as amended, and Section 21E of the Securities Act of 1934 as amended. Forward-looking statements are those concerning VAALCO's plans, expectations and objectives for future growing, completion, and other operations and activities.

All statements included in this presentation that address activities, events or developments that VAALCO expects, believes, or anticipate will or may occur in the future are forward-looking statements. These statements include expected capital expenditures, prospect evaluations, negotiation with governments and third parties, 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 and Form 10-K for the year ended December 31, 2012, and other reports filed with the SEC that can be reviewed at www.SEC.gov.

A few comments before I turn the meeting over to Greg for his financial review, and then Russell, for the operational update. Our earnings per share somewhat masked quite a strong 2012. Operating cash flow was high at $95 million and we increased our reserves by over 24%. We drilled a discovery well onshore Gabon, and we've entered into a new country in Western Africa, Equatorial Guinea. We have crept ever closer to drilling our much-anticipated exploration well in Angola, and we'll talk a little bit about that later on.

I think since we are a successful efforts reporting company, our drilling and lack of success in Montana necessitated steep write-offs against earnings during the year nullified what actually was a good year for the rest of our operations. Most of those write-offs are now history, as we decided to exit our domestic unconventional shale plays and concentrate on our African holdings. Towards that end, we have closed our Denver office and have commenced a six-well drilling program offshore Gabon, which Russell will discuss further in his report.

The ever-allusive start of our drilling in Angola is truly creeping forward. In our third-quarter conference call, I mentioned we had found a partner, and I can assure you we still have that partner. Our work program has been approved by the Angolan government, and the only missing piece of paper is the assignment of the 40% working interest to our new partner.

Earlier this week, we were told that everything was in order and we would be notified shortly. We believe that will happen. And since all long-lead materials are in our yard, and the sites already completed, all that is needed is that piece of paper to get started. We are continually monitoring the rig market, and are led to believe a rig will be available when we are ready.

I will have a few more comments later after Greg's and Russell's report. And with that, I'll now turn it over to Greg for his financial review.

Thank you, Bobby, and good morning, everybody. Thank you for joining us for the call. I'm just going to take you through a series of numbers here, essentially talking about the fourth quarter and the full-year results. And after I finish, I'll turn it over to Russ for the operations update.

To start out, net income attributable to VAALCO for the fourth quarter was a minus $18.9 million. And, as we know from what Bobby just mentioned and what you've read, that's attributable to our lack of success on our drilling in Montana. For the fourth quarter of 2011, we had a $8.7 million positive net income. For the full-year 2012, VAALCO reports $0.6 million compared to $34.1 million for 2011.

On a earnings per share diluted basis for the quarter, we lost $0.33 a share compared to $0.15 in quarter 4 of 2011. Full-year, we were at $0.01 for 2012 compared to $0.59 for 2011. On the cash side, we're sitting incredibly solid, as we typically are. We ended the year at $130.8 million of unrestricted cash. That compared to $137.2 million in the prior year. Restricted cash at the end of this year, 2012, was $12.1 million, essentially the same as in 2011 at $12.2 million. The majority of that restricted cash is a guarantee for drilling two wells at Angola. We hold those funds in a bank in the United States.

Moving to oil revenues, in Gabon, fourth-quarter 2012, our oil revenues were $52.9 million compared to $67 million in the same quarter a year ago. For the entire year, we were at $192.5 million, 8% lower than our 2011 figure at $208.8 million. I'll show a little bit US information as well. Our US oil revenues from our Granite Wash properties for the fourth quarter was $200,000, exactly the same as the same period a year ago. And for the entire year, oil revenues were $800,000 compared to $300,000 in 2011.

Gas revenues in the US, this is primarily in Granite Wash, for the quarter, were at $0.4 million, slightly less than a year ago in the same quarter at $0.5 million. For the entire year, our gas revenues were $1.9 million. And for the prior year, $1.3 million. So, slightly up.

Talking about volumes and prices, if we look at the oil in Gabon, we've lifted 482,000 barrels in the fourth quarter of 2012. That compared to 604,000 barrels in the same period a year ago. For the entire year, we've lifted 1.7 million barrels, 7% lower than our 2011 figure of almost 1.9 million barrels. On the oil side -- and those are gross numbers, by the way -- on the oil side in the US, we sold 2000 barrels in the Granite Wash in the fourth quarter, the same number in the same period a year ago. For the entire year, we sold 10,000 barrels of Granite Wash oil compared to 4,000 barrels in 2011. 4000 barrels in 2011.

On the pricing side, we had strong pricing in oil in both -- for our Gabon oil and our US. In the fourth-quarter 2012, our Gabon oil price was $109.80. In the same quarter a year ago, it was just slightly over $111. And for the entire year, it's almost identical for 2012, $111.24 on average; and in 2011, $111.98. Oil prices in the US for the fourth quarter, just under $78. For the same period a year ago, it was $85.60. For the entire year, we sold our oil at $81.68 a barrel; and in 2011, $79.71.

Real quickly, gas volume and prices; and this, again, is primarily with our Granite Wash properties in Texas. In the fourth quarter of 2012, we sold 111 million cubic feet compared to 100 million cubic feet in the same quarter a year ago. For the entire year, we sold 532 million cubic feet in 2012; 255 million in 2011.

On the gas prices -- and these gas prices include liquids -- our price in the fourth quarter, $3.73, which is again combined -- it's a dry gas price plus the value of the liquids. In the fourth quarter a year ago, it's $5.06. So, a fairly dramatic decrease, but not on huge volumes. For the entire year 2012, we were at $3.66, and that compared to $5.23 for 2011. Big decrease in there were the fallout of natural gas liquid prices during the course of 2012.

Moving to just a couple of indices here in expenses, production expenses during the fourth quarter were $8.7 million. That compared to $11.2 million in the same quarter a year ago. For the entire year, we were identical at $26.7 million for both 2012 and 2011. On a per-barrel basis, in the fourth quarter of this year, we were at $17.33 a barrel. That compared to $18.02 a barrel a year ago; and for the full year, [$14.60] per barrel this year; $13.99 for last year.

The uptick in the fourth quarter and how it impacts the entire year is, we renegotiated the FPSO rates, where we've got the FPSO on contract for several more years. And there's a bit of a rate increase associated with that. Russell could actually talk more to this, but we actually have a very good deal with our FPSO.

Exploration expense is the big item, obviously, for the quarter and the year. During the quarter, we had exploration expense of $36.0 million, and that's primarily associated with five domestic dryholes. For the same period a year ago, we were at $2.1 million, minimal exploration expense. For the entire year, we were at [$41 million] for 2012 compared to $5.7 million in 2011.

Depletion per barrel -- I mention this one because the indices have changed quite a bit. For the quarter, we were at $6.36 a barrel compared to $12.62 -- almost double a year ago. For the full year, $10.88 a barrel and for the entire year of 2011, $13.39. The reductions in those are primarily associated with the reserve increases that we received at the end of the year from our independent reserve analysts. We'd take those rates and we'd take them back to our fourth quarter. So the increase in our reserves, which I believe Bobby mentioned, a 24% increase, has the positive impact of lowering the depletion rate per barrel.

Speaking of reserves real quickly, our reserves -- proved reserves went up -- pardon me while I pull my information here -- so we were up 24% on proved reserves, up to a little over $7.4 million (multiple speakers) -- barrels -- sorry.

And if I move from there, Bobby had mentioned that the majority of the dryhole costs are behind us. We did have a -- our fifth well that we drilled. This one was in South Dakota, which was unsuccessful. We have $2.8 million of that that we will recognize in the first quarter of 2013. The well was actually spudded in January of this year. And so the majority of the costs associated with that well are in 2013.

Lastly, I'll just mention that you probably saw that we had a acquisition of a noncontrolling interest on the offshore Tom block. The $26.2 million purchase is a little bit confusing, I can tell from some of the comments I've gotten. Our working interest has not changed at all. We have a 28% working interest in the block, but that 28% working interest in the past was owned by an entity that VAALCO owned 90%. We had an opportunity to purchase the remaining 10% from another company that happened to have been one of our partners, but that really doesn't matter. But we picked up that acquisition of that 10% for $26.2 million.

And so when you look at our financials, and you see references to noncontrolling interest in terms of revenue or distributions, that ceased with the end of third quarter of last year. If there's more questions on that, I'll be glad to take those on.

With that, I'll turn it over to Russ to kind of take you through the operations, that side.

Thanks, Greg. I'll go through our offshore Gabon and Tom drilling plans, and expansion plans, and talk a little bit about the offshore discovery; introduce you to Equatorial Guinea and what we could have done there, and wrap up with a discussion on Angola.

But before I do that, I might -- some of you may be aware that there is a nation-wide strike by the oil union ongoing in Gabon. This came about as a result of the strike against Schlumberger that started around New Year's. Schlumberger responded with releasing some employees and it's been a long strike against Schlumberger. It has not impacted our drilling operations. They've been providing services using ex-pat personnel, which, of course, the union is not happy about.

So they decided to attempt to make this a nation-wide strike against all the service companies and all the producers. The strike's been going on for eight days now. Our production has not been affected. Our employees have chosen not to participate in the strike. We have personnel that worked for Kenworth, which operates the FPSO that we produce our oil into. They have union members. Those union members have chosen to participate in the strike in the form of providing, quote/unquote, "minimal services," in the form of reduced meals and reduced laundry, and some things that are -- you know, so that they can at least report back to the national union that they are participating.

So, our production has not been affected to date. Don't know how much longer this is going to go on. It's a pretty recalcitrant situation. And it's over the usual issues of ex-pat workers and better wages, and particularly, over this issue of the Schlumberger strike and the fact that Schlumberger eliminated some employees in association with that strike. So, right now, we're producing in excess of 17,000 barrels a day. And we hope to make it through. And hopefully, this thing will get settled in days, not weeks.

So going into what we're doing at Etame, we started our drilling program with the 350-foot jack-up rig, the KC Joytag Benrinus at the beginning of this year. Our first well is a development well, the Avouma 3-H well. And we have successfully drilled that well to the target zone. As I mentioned at the last conference call, we had reprocessed seismic, and we had identified a new area within the Avouma field that we thought was potential.

This new well found the Gamba five meters high to the Avouma 2-H well, which is the main producing well in the Avouma field, or about 15 meters higher than what we had originally mapped that area. So we were successful in proving up new reserves in that area. The well is currently being completed with gravel pack screens. And next week, we'll be running in the submersible pumps, so that we can put the well on production later this month or early in April.

We estimate that the success of this well will increase the ultimate recovery of the Avouma field by 1.5 million to 2 million barrels. After we finish with that well, we've got two workovers at Avouma on tap. The first will be to return the South Tchibala 1-H well to production. That well has been down for a number of months because both pumps in the well failed. We'll replace those pumps and get that well back on production.

The second workover will be to replace both pumps in the Avouma 2-H well. In that well, one of the pumps has failed. The other one is still working, so we are still producing that well. But we have a policy of any time we have a rig around and we have a failed pump, we're going to go ahead and replace both, so that we have redundancy.

When we finish at Avouma, we'll then move over to the Ebouri platform. I think the last two quarters I've talked about an exploration well there. It's within the development area, so it's not officially an exploration well, but it is in a new fault block. We'll be drilling that well. It has the potential to add 7 million barrels gross, which would be about 1.7 million barrels net to VAALCO if it's successful. It's also got some deeper objectives in the Dentale that could add another million barrels or so if it's successful.

If that well works, we will complete that well as a producer. It's in a fault block that's south and deeper than the existing Ebouri field. You may recall we had a couple of wells that started producing H2S back in July that we had to shut in. Those wells are in the northern end of the field and shallower, so we don't anticipate any issues with H2S in this new test.

We then got our remaining well in Ebouri, the 2-H well. It's got one pump that's down, so we're going to go ahead and change out both pumps in that. So that we'll have fresh pumps in there that, hopefully, should last for two, three, four years, is what -- is the run life that we get.

Once we finish with the platform work, we have an exploration well that has now been approved by the consortium. It's a 38-million barrel Gamba prospect. It also has deeper potential in the Lucina, which is below the Gamba. It's a turbidite formation. We'll drill that well probably in the July or August time frame, depending on how the campaign goes on the platforms.

We're then going to turn the rig over to another operator in Gabon, and they have a two-well program that they'll use the rig for. And we've negotiated for an additional two slots beyond the six that I've just discussed. They're optional. But during the time that we're finishing our drilling program and the rig is with this other operator in-country, we will be able to complete the depth processing on our shallow water seismic.

We have three prospects -- or three leads, excuse me -- we have three leads in that area that we'll firm up one way or the other. So I would anticipate when they finish with the rig, we'll take it back, and either drill one or two exploration wells, which would occur sometime late third or early fourth quarter of 2013.

During the fourth quarter of last year, we got final investment decision on the two new platforms that we're going to be putting into the Etame area. We have also obtained government approval last month for those platforms. These platforms have been awarded for fabrication to Gulf Island in Houma, Louisiana and construction is underway. One of these platforms will be installed at the Etame fields at infill wells to replace, for example, some of the wells that have gone down because they don't have artificial lift, and the water cut has come up and they can no longer produce. We anticipate three to five wells over the life of the Etame platform.

The second platform will develop the Southeast Etame discovery, as well as we're going to try to develop the North Tchibala field, which is the Dentale field. The Dentale is below the Gamba. There were several penetrations in this field back in the '80s, and tests of 25, 100 barrels a day from some of these zones. So, they can produce. They're probably not as prolific as the Gamba, but it's a large accumulation, over 100 million barrels of oil in place. So we're going to see how we fare in the Dentale.

The North Tchibala field also has a gas resource. And we need that gas for down the road when we run short on gas to run our generators and our ESPs. So we'll be developing that resource off of that platform as well.

These platforms are scheduled for installation in 2014. Each platform is a $32 million to $36 million investment for VAALCO plus the cost of wells. Each well is around $7.5 million net to VAALCO. And so it's a fairly major campaign.

The good news is, though, that with this cost oil that we have, literally, the platforms will have paid out when we complete the installation of the platforms. Because this whole time, we're able to recover the cost of building and installing the platforms out of the cost oil. The goal of this project, obviously, is to get production up. We expect that we will be able to maintain production near or above 20,000 barrels per day through 2016 by the combination of the work program that we have going now, and the installation of these two platforms in 2014.

With that, I'll move to the onshore area at Mutamba, the N'Gongui discovery that we announced last quarter. We have filed for an exploitation area over that field. And as a result of that, we will be required to file the development plan, which we plan to do this year in conjunction with our partner, Total. We envision tying this field back to a field called the Atora field, which is about five miles away from our discovery. This is a field that's operated by Total, so they're obviously okay with us tying into them since they're our 50% partner. And we'd like to commence the development of this field in 2014.

I'd like to talk next about Equatorial Guinea. In November of last year, we closed on an acquisition of a 31% interest. We bought it from Petronas Carigali in a development area called Block P, which is offshore Equatorial Guinea. The block is operated by GEPetrol, which is a national oil company which has a 58%. And then there are two other partners with about 5% each.

The block contains a 2007 Gabon discovery. It's known as the Venus discovery, which found a 300-foot oil column in a channel sand. It's in about 800 feet of water depth, and there are numerous other channels on the block to explore. And so the plan is to commence a two-well drilling program to explore some of these channels to see if we can't expand the resource base there.

We're in the process of negotiating to become the technical operator on behalf of GEPetrol. GEPetrol is really not set up to drill wells and run platforms, et cetera. So we are attempting to work out an arrangement where we would become the technical operator, and they would remain the administrative operator. What that really means is we become the de facto operator. We'd be in charge not only of the technical side, but the money matters, as well. And then they would be the administrative officer in terms of dealing with the government, et cetera.

We have located a rig for these two wells. It is currently operating in Nigeria, which is just to the north of Equatorial Guinea. The operator who has that rig has it under long-term contract. And they mean to lay off two well slots sometimes in the third or fourth quarter, to allow them to sort of consolidate some of their evaluations on their current drilling program. So if we can work out the arrangement with GEPetrol, we'd hope to be drilling in Equatorial Guinea this year.

With that, I guess, I'll just touch on Angola. It's kind of the same story, but we think we are making progress finally. We have a two-year extension until November 30th of 2014 on our acreage. Sonangol has approved the partner, and they have sent a letter to the Minister of Petroleum, approving the new partner. So now we are dealing with the Petroleum Ministry to get the final approval, which is in the form of a publication that they have to publish that this new partner has been assigned the interest. And we think that is imminent.

Once we get that publication, we're good to go. And Bobby mentioned we've got the prospect identified that we want to drill. The partner wants to drill it. We also want to acquire some additional seismic out of the deeper water, where on 2D, we see some structures comparable to what Cobalt drilled when they made their Kwanza Basin discovery.

So with that, Bobby, I'm going to turn it back to you.

Thank you, gentlemen. And just a few added comments before I open it up for questions.

I think it's important to recognize the reason for some of the decline in our production last year was because we shut in two wells in the Ebouri field due to the presence of H2S. And thus, some decline there. I think also that what Russell mentioned is important to note that this new well that we're completing in the Avouma field, that could add about 3,000 barrels a day to our production. And that's where -- which he mentioned -- we'll get close to 20,000 barrels a day, up from 17,000 that we currently are producing.

About the strike in Gabon, these strikes are normally settled fairly quickly. Obviously, the government wants them settled quickly, because it hurts the revenues of the country of Gabon. So, we'll see what happens there.

The problem with the strike for VAALCO, it's delayed our negotiations with the government, as Russell mentioned again, on the renewal of our concession onshore in Mutamba. I know a number of you are curious about the size of our reserves that we have there. We really can't go into that because of the negotiations we're in with the government.

But suffice to say, it's a commercial discovery. And that would give some indication that we can make some money out of it. But I'm going to have to leave it there until there is some clarity from the government on the settlement of the strike, and our success in negotiating an extension for the Mutamba concession.

There's other things that we can go into, but I think I'll open it now, Stephen, to questions from the outside. So I'll turn it back to you.

(Operator Instructions). Leo Mariani, RBC Capital Markets.

Obviously, you're all thinking that you're going to get imminent final government approval on your partner. What do you think the process is after that to drill a well? Would you have to go out for rig tender? Do you have something that you're kind of already eyeing? Trying to get a sense of when a rig could show up and potentially drill this first prospect.

We have been in sort of constant communication with the rig market to understand what's available and what's not. We will have to make an official tender under the rules that we operate under in Angola, so we'll have to go through that process.

We've actually already been through the process of tendering for casing, tubulars, wellheads, et cetera, and we purchased the long-leadtime items and warehoused them. I mean, we could use those anywhere. We could use those in Equatorial Guinea or Angola, or whatever. So we went ahead and got the long-leadtime items in stock. So it will take a few months to go through the process. It's a little more arduous in Angola than it is in Gabon, in terms of what you have to go through to get official approvals. But we would just march on down the road and try and get it done.

There are several rigs out there that can do this work that are available in fourth quarter -- first quarter -- fourth quarter this year, first quarter next year, as we speak. Obviously, the longer this thing goes on, there's a chance somebody could pick one of those off, but there are some rigs available right now.

(multiple speakers) Leo, I was just going to chime in, you didn't ask, but another consequence of getting the new partner assigned to us from Angola is our ability to go to that partner for the costs attributable to the 40% since when the former partner departed. So we've got $6 million that we provided for as an allowance on our books that we expect it will come back as net income, once we get that new partner assigned to us. And the $6 million is actually principle. And the agreement is $6 million plus interest. So, that's a positive impact to our 2013 financials once that event occurs.

And while we're on improvements to our financials -- Russell, stop me if I'm wrong -- but I believe with the pickup of this 9.99% interest from a former partner of ours, we estimate that should add close to $5 million of income to our earnings during 2013 -- $5 million to $6 million, yes.

It actually does. The last three years, net income attributable to that 10% was $16 million. And we also made cash distributions during that same three-year period of almost $19 million. So we feel that that pickup was really good, especially with all of the positive things that we're going to be investing in, in the country.

So, gentlemen, that's over $10 million, close to $12 million of additional income you can look forward to in 2013, if everything goes according to oil.

No, that's helpful. And I guess in terms of your new partner there in Angola, I know you guys have yet to reveal the identity, are you -- it sounds like you've already been in discussions with them already about your plans here. Do you guys are trying to think that you're both kind of singing the same tune, and both want to get out there and get aggressive with the drill bit sooner rather than later? Do you feel like your interests are really aligned with this new partner?

Yes, that's the whole point, is that -- I mean, they've bought into the well we want to drill and they're agreeable to acquire the deepwater seismic, so.

And they've agreed, they know about the monies in arrears that are wrote to us and they understand all that -- or we think willing to go forward with that also. It's a good partner. We get along very well. And so it ought to be a good partnership.

And they're bigger than us, so there's no issue of them coming up with their share.

Okay, that's helpful. And I guess you talked about Mutamba, Russell, in terms of starting development in 2014. If all goes according to plan, I mean, when do you think we would get first oil potentially there?

In 2014.

Okay. And you think that would be later in the year? Is that more back-half-weighted? Or how should we think about that?

Yes, I think it'd probably be later in the year. It's going to be a multi-well development. And as we mentioned, there's gas on top of the oil, so we'll have to ease our way into that. But it should work out just fine.

Okay. And just a couple of questions around some of the expenses here. So, you guys did address the DD&A rate, which I guess got cut in half this quarter, roughly speaking. You talked about reserves going up 24%. It seemed like an awfully big move. I mean, are we going to be really expecting kind of $6 a barrel and change going forward? Or is this more anything here that may be anomalistic in the quarter?

Leo, those rates should be representative of what we're going to see in the time coming up. Sorry, earlier, I couldn't find my piece of paper on the reserve picture. But we ended up last year 2011 at a little over 6 million barrels proved reserves. We had production of 1.7 million, which takes away from that number, but the revision of our previous estimates was a solid 2.2 million.

So this was re-evaluation. Russ talked about going out on Avouma and testing a new flank there that we're going to bring that well in on. And we've got a fairly significant increase from our independent reserve analysts with regard to our existing structure. And then on top of that, we had extensions and discoveries of almost 1 million barrels added to our reserve -- proved reserve base. And that was with the forward movement on the development of our Southeast Etame prospect. So we ended up the year at 7.5 million proved reserves.

Okay, that's helpful. And I guess in terms of your lease operating expense, that was sort of up this quarter versus the past few quarters. I'm just noticing a pattern where you guys seem to have higher fourth-quarter operating expense than the prior quarters in the year. Just trying to get a sense of how we should expect that in 2013. Is it going to drop back down a little bit? Or should we be thinking this $17.33 as kind of a go-forward number here?

Probably, Leo, due to us eliminating a lot of our US onshore activities, that should decrease somewhat. And we had some catch-up associated with signing an amendment to the FPSO contract. The FPSO has now been extended to 2022; firm to 2020 with two one-year options to 2022.

Basically, in return for that, we had to up the CapEx rate. It's a stairstep over three years. And that CapEx rate is then for them to make whatever repairs are necessary to keep that thing out there for another 10 years. And that's in the form of repair to the hull, some -- redoing the generator that we use out there to produce all our steam and power; a number of things that they have to address. But that's in their bailiwick -- the risk is on them, not on us, as long as we pay that increased CapEx rate. And it was retroactive to January 1, so there was kind of a catch-up to that.

(multiple speakers) Okay, that's helpful -- and I guess -- sorry, go ahead.

I was just going to say, I think if you're just looking at the numbers, probably fourth quarter would be higher than what we would expect in 2013. But if you look at the overall [$14.60] for all of 2012, we'll probably be higher than that.

(multiple speakers) That's helpful. And I guess (multiple speakers) --

And keep in mind that these workovers that we're going to be doing will hit operating expense. They're OpEx workovers; they're not capital workovers. So, those workovers are roughly $8 million a piece to about -- to, excuse me, gross. So that's going to be something around $2.5 million to $3 million to VAALCO. So you're going to see a big chunk of OpEx for those workovers hitting in 2013. So you ought to keep that in mind, to your point.

Okay. And I guess in terms of your US assets, are you guys pretty much done there? Have you kind of written everything off? Should we not expect really activity going forward? How should we think about that? Would you guys move to maybe sell those, or --?

Well, we're talking about that, Leo, what's the best way to complete an exit strategy. A sale is a possibility.

We've got 22 million acres -- excuse me, 22,000 acres on Poplar Dome, all contiguous oil held by production. And I read the other day in Upstream Magazine, an article on Fort Peck Indian Reservation -- that's where we are, that's where Poplar Dome is. Interestingly enough in that article, they say that there's 450 million barrels of Bakken oil underneath Poplar Dome.

Maybe somebody else has a better key at getting it out than we did. But it's good to hear the United States government, at least, thinks that. Of course, we all know the government is never wrong. So we'll see what happens. But the thought at the moment is, let's package this altogether; let's sell it and let's get out of here and get back to West Africa.

I would mention that we remain with a lot of cash for a small company like VAALCO. Since we bought that 9.9% interest for 26-some-odd-million-dollars, we still have a little over $130 million in cash on our balance sheet. Our capital projections this year is around $83 million to $85 million. So I mentioned that our operating cash flow was $95 million last year.

So we're still projecting of operating within our cash flow. Now if we drill one more exploration well in either Angola or perhaps Equatorial Guinea, that will add to our capital budget by $15 million, $16 million. So we might need to get a little bit of our cash back from JPMorgan. But financially, we're still in great shape. And our searching our neighboring countries, if you want, and West Africa for additional opportunities. And we hope to be able to report within the year that we've been successful in finding additional opportunities.

All right. That's very helpful, guys. Thanks.

Bill Dezellem, Tieton Capital Management.

I'd like to circle back to your expectations for 2013 production. If you do not get the wells that have been shut-in due to the H2S back on line, how do you believe your production will compare in '13 versus '12?

Just by the one well that we are going to put on line in Avouma that we're drilling, that will add -- we've got some natural declines, so it looks like we're going to be pretty much even or slightly ahead in 2013 than 2012.

Thank you. And your prospect for actually getting those H2S wells back online, you mentioned that you were going to be doing some activities there that was going to require some CapEx. How, when you really look at that objectively, are you feeling, both from a timing standpoint and from the perspective of realistically whether you're going to be able to get those wells back on at any point?

Well, we've come up with a solution. We hired a firm that we've worked through the engineering of how we can clean up the H2S from those wells. It's basically we're going to have to build a small platform adjacent to the Ebouri platform, put a lot of heat on there to heat the oil, to drive out the H2S. And then you cascade the oil down a column with the oil coming in the top, and sweet gas coming in the bottom. And that gas basically absorbs the balance of the H2S and you end up with clean oil.

It's nothing new. It's been done in Gabon by Marathon on their Tchatamba platform, where they had sour wells. It's just -- we're into what we call pre-feed or pre-front-end engineering and design. That will take about six months, at which point we would then award the engineering contract to design the facilities, and hopefully, start construction on them sometime next year or probably late next year, with the idea that we'd be out in the field a year later installing all this.

So we do have a solution. Unfortunately, it costs money, but there's a pretty good prize there in the form of 7 million to 10 million barrels that we would not be able to get if we don't go ahead and do something like this.

So to make sure that I understand from an economic standpoint, return on investment, it absolutely -- it will be economic to (multiple speakers) --

(multiple speakers) Oh, yes. Yes.

-- to invest this money and get these wells back online?

You're talking about 7 million barrels, which -- or 10 million barrels, which is $700 million to $1 billion. And a small platform with these facilities is on the order of $100 million. So it's definitely something we'd have to do.

And that's -- one-third of that's VAALCO's cost.

Sorry, I'm talking all in gross numbers.

Yes.

Sure. And yet if we also heard you correctly, the construction will begin the second half of next year. So this is really a '15, 2015 phenomenon when the production would be expected to come back online?

Right. And keep in mind that we shut-in about 2000 barrels a day, but we still have a producer in Ebouri. And we've actually been able to optimize that well and get maybe 500 barrels of that 2000 back from the existing producer.

And our models say that that well should not sour until 2016 or so. So hopefully, we can get everything in place to bring all three wells back, plus we have a couple infill opportunities once we get those facilities.

Great. Thank you both.

Due to time constraints, our last question will come from the line of Neil Nelson of DERS Group. Please go ahead.

(technical difficulty)

Pardon the interruption, Mr. Nelson, we're having trouble with your line. It seems to be breaking up. Is it possible that you could pick up a handset?

I'm on a handset.

Okay, you're coming through clear now. Please proceed with your question, sir.

Are you acquiring any long-lead items for drilling in Equatorial Guinea to cut the lead-time on (technical difficulty) --?

Yes, we actually have three sets of long-lead items that we had acquired for Angola. And we are, in addition, acquiring additional long-lead time items for potentially drilling in deeper water in Gabon.

If that Gabon project isn't approved, the situation is such that we can spin those things off. And we're not talking big dollars here. We're talking $1.5 million, $2 million worth of kit that we're acquiring. And if we, for whatever reason, decide not to use it, there's other people out there that are looking for the same kit. So, we should have five-plus wells worth of long-lead items in our universe, if you will, by the third or fourth quarter.

And have you considered each of (technical difficulty) enhanced (technical difficulty) water flood or other types of enhanced oil recovery in the Etame field as it declines?

You know, we fully expect to get over 50% recovery from those reservoirs, which is pretty darn good. And the water drive is so strong there that with these ESPs, we'll be dragging that oil up to 90%, 95% water cut. And all our platforms will have water knockout on them, so that we won't be overloading the FPSO with a bunch of water.

All the platforms will be sending basically 90-plus-percent oil to the FPSO. So, we think we have a pretty good handle on the recoveries. And we're not looking at any sort of CO2 plugs or anything like that. We don't think there's opportunity for that type of thing.

Okay. Thank you very much.

I would like to turn the floor back over to today's panel. Please go ahead, gentlemen.

Well, gentlemen, thank you very much for your attention. And I hope we answered most of your questions. And look forward to seeing you in the first quarter. Thank you all. Thank you, Stephen.

You're welcome, sir. And ladies and gentlemen, that does conclude our conference call for today. On behalf of today's panel, I'd like to thank you for your participation and thank you for using AT&T. Have a wonderful day. You may now disconnect.