VAALCO Energy Inc (EGY) 2007 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the year-end earnings 2007 conference call. At this time, all participants are in a listen-only mode. Later we'll conduct a question-and-answer session. Please note that this conference is being recorded.

I'll now turn the call over to Mr. Robert L. Gerry. Mr. Gerry, you may begin.

Thank you, John, and good morning, ladies and gentlemen, and welcome to VAALCO's year-end and fourth quarter 2007 conference call. Please bear with me while I read our forward-looking statement.

This conference call includes forward-looking statements as defined by the U.S. Securities laws. Forward-looking statements are those concerning VAALCO's plans, expectations, and objectives for future drilling, completion and other activities and operations. All statements included in this conference call 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 future production rates, completion and production timetables, and costs to complete wells. These statements are based on assumptions made by VAALCO, based on its experienced perception of historical trends, current conditions, expected future developments, and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond VAALCO's control. These risks include but are not limited to inflation, lack of availability of goods, services and capital, environmental risks, drilling risks, foreign operational risks, and regulatory changes.

Investors are cautioned that forward-looking statements are no guarantees of 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, 2007, and other reports filed with the SEC, which can be reviewed at www.sec.gov, or which can be received by contacting VAALCO at our company's headquarters, 4600 Post Oak Place, Houston, Texas.

Let me start off by saying that all of you, I hope, have read the press release which we released earlier this morning, but if you didn't it is posted on our website, which can be accessed at www.vaalco.com. As we mention in our press release, and as most of you probably know by now, we received a letter from a stockholder reporting ownership of approximately 8% of VAALCO requesting certain actions by the company. The Board of VAALCO acknowledges receipt of the letter and will evaluate its contents in due course. During this conference call, it would be imprudent of me to respond to any questions regarding the content of the letter, but I will be glad to answer questions regarding the operations of the company and our future plans.

I'm going to come back in a minute here after Mr. Scheirman, Russell Scheirman, takes you through our 10-K and brings you up-to-date on our activities, and what we perceive the next year looks like for the operations of VAALCO. So with that, Russell?

Thank you, Bobby.

For the fourth quarter of '07, we sold 424,000 net barrels at an average price of $87.03 for revenues of $36.9 million. That compared to 277,000 barrels sold in the fourth quarter of '06 at an average price of $57.36 for revenues of $15.9 million. Our operating costs in the fourth quarter of '07 were $19.5 million compared to $7 million in 2006. Included in the operating costs of '07 is an $8.1 million dry hole charge for a well that we participated in in the North Sea, as well as higher depletion costs that we are experiencing as a result of bringing the Avouma field on, the Avouma and South Tchibala fields on in 2007. The development of those fields occurred at service costs at the time in 2006 and 2007, as compared to the Etame field, which was developed back in 2002 with much lower oil field service costs. That gave us operating income for the quarter of $17.4 million in 2007 compared to $8.9 million in 2006.

We had other income of about $800,000 compared to $700,000, and then we had income tax expense of $14.8 million in '07 compared to $3.4 million in '06. The large increase in income tax reflects the fact that in 2006, we had large income tax deductions associated with our drilling program for Avouma and South Tchibala, whereas in 2007 we had not a lot going on other than the construction of the Ebouri platform, so we were taxed at a much higher rate in 2007. After deducting the minority interest charges, we then end up with net income of $2 million or $0.03 per fully diluted share in the fourth quarter of '07, compared to 5.3 or $0.09 per fully diluted share in 2006.

For the full year 2007, we sold 1,759,000 barrels at an average price of $71.16 for revenues of $125 million, compared to 1,554,000 barrels at $63.26 for revenues of $98.3 million in 2006. Our production was up, due to the addition of the South Tchibala and Avouma fields in 2007, as well as debottlenecking of the FPSO that allowed us to increase our production rates to something over 22,000 barrels a day that we're currently producing.

Operating costs for the full year were $56.3 million, compared to $24 million in 2006. The biggest components of the increase in operating costs, our exploration expense, went from $2.7 million in '06 up to $15.3 million in '07, reflecting both the North Sea dry hole activity, seismic acquisition projects in both Gabon and Angola, and just a much fuller exploration and activity schedule than we had in 2006. The other big piece of the increase was depletion, which went from $6.7 million when we only had Etame on 2006, up to $18 million with the addition of Avouma and South Tchibala. The depletion rates run about $6 a barrel at Etame and $15 at South Tchibala and Avouma, just so you can get a comparison, and on a blend we're at about 10.

That gave us operating income of $68.7 million for the year '07, compared to 74.3 in '06. We had other income of 2.9 as compared to 1.9, and our income tax expense was $48.1 million, compared to $30.5 million in 06. You should really look at that income tax number against our revenue number, because with the addition of the onshore Angola - excuse me, offshore Angola, onshore Gabon, and the North Sea, those projects do not expect our Gabon income taxes, so anything we spend do not get deducted from taxes. The taxes - the Etame field, or the Etame block is ring-fenced, and anything that we spend in Etame, we can deduct, but anything we spend outside of the Etame area, since it doesn't have revenue at this time, it - we don't have any tax savings there. After we deduct the minority interest, we end up then with net income for 2007 of $19.1 million or $0.32 a share, compared to $40.3 million or $0.67 per fully diluted share in 2007.

With that, Bobby, I'll turn it back to you.

Okay, Russell, thank you. Let me go through what I think are some of the highlights that we accomplished in 2007, and give you a brief snapshot of what we believe is the excitement for the next few months through - and certainly through 2008. We did replace our production this year with additions to our reserves. We ended last year at our - 2006 at 6.0 million barrels roughly, and this year we got some credit and some additions, so we ended the year at 6.2 million barrels.

If you take the proved and probable reserves at VAALCO, which we mentioned in our press release, we are now in the neighborhood of 10.4 million barrels, which your Management feels is a pretty solid undertaking, and we believe that's the number that most people should focus on. We are ramping up our production in the Etame field. We have hit a high of 23,000 barrels, or slightly in excess of that. We're now around 22,500, but we are making some changes where we hope to remain above that number and get close to 25,000 barrels.

The Ebouri platform that we've been building for the better part of the year is virtually complete now in Ingleside, Texas, near Corpus Christi, and is scheduled to start the tow to Gabon April 25th. We have signed up a rig to commence the drilling of the development well in Ebouri; it should commence drilling in October, with first oil scheduled for December. Ebouri is becoming a very exciting field for VAALCO and its partners. We now believe that this field could contain 24 million barrels, and when added to the 11 million that we currently believe it holds, we're up to 35 million barrels. This is a triple of our original estimates.

What we hope to do is this summer, and I'm not going to give you a date because we're out in the marketplace searching for a rig, and we have a few other hurdles internally to jump through, but we hope to procure a rig to drill a step-out in Ebouri, to test what we call north Ebouri. If this works, that will be the key to our now thought process of having - that Ebouri could contain 35 million barrels. That well will drill, we hope, before the development well at Ebouri. The development well, again, first oil in December, we expect that well to produce between 4 and 6,000 barrels when it comes on stream, and we're very excited about that.

That rig will then go to another location in Gabon, where we will drill an exploration well. If everything goes according to what we hope it will go, we'll probably drill four or five wells in the next 12 months on our offshore Etame project. We also intend to drill two wells onshore, on our Mutamba concession, where VAALCO owns 100%. We hope to commence the drilling of that in the Fall of this year, and I mean the Fall, October. We are in the marketplace searching for a rig currently. We are engaged in an environmental impact study at the moment. Our people have been out to the site. They think that it's very doable, and again, the only question there is when we can contract for a rig.

So Gabon in itself is a terrific upside potential for VAALCO,. Were I've mentioned in the press release that we are going after unrisks, 100 million barrels, a lot of it will occur in Gabon, but also we are now proceeding rapidly with Angola. We have identified a large structure on our Angola concession. It could hold up to 300 million barrels. We are in the process of procuring a rig for that, but I caution you, it's 300 million barrels in place; and the secret will be, what would be the recovery rate of that? It could be anywhere from a low probably of 15% to a high of 35%, but that is part of the impact of the growth, sort of 100 million - or net 100 million barrels that we are after.

So what we've been working on for a period of time here, well over a year, we now see coming to fruition. It's our belief that our stock price has reflected a slow pace, but the pace believe me has been fairly rapid here in the office. We are now moving to the drilling aspect and the Management here and the employees of VAALCO are extremely excited about the outlook. Our stock probably remains depressed because of the lack of reserves. That's always been the knock on VAALCO, that we have a low reserve base, but Management does not believe that. Again, I reiterate our proved plus probable is more in the neighborhood of 10.4 million barrels, and we would not have signed up the FPSO to the year 2015, or have the option of the year 2015, if we did not believe that we could utilize the FPSO for that period of time.

Again, I'll reiterate, we're very excited. We believe that 2008 is the break-out year for VAALCO, and we continue to search for other opportunities. But again, we believe that this is the year that VAALCO will become recognized with the opportunities as they come to fruition. The next lifting in Etame is scheduled for in a few days. We will lift about 550,000 barrels.

But with that, I think it's probably opportune now to go ahead and open up for questions and answers. So go ahead, John, why don't you see what's out there?

Thank you. We'll now begin the question and answer session. (OPERATOR INSTRUCTIONS) Our first question is from Kenneth Pounds. Please state your name and what firm you are from. Please go ahead with your question.

Hi, Kenneth Pounds, Nutmeg Securities. A couple of questions. It sounds like you are really speeding up the pace and expanding opportunities in Gabon and also Angola. You didn't touch on the new, what was it, at [Cafarmin] in the North Sea. Could you talk a little bit about that, and what the potential risk/reward with that is? Thank you.

Sure. It's a gas prospect. It should be drilled in the August/September timeframe of this year. The target is around 50 Bcf. It would be a single field development tied back to an existing platform that is a few miles away. It's operated by a company called Century Energy, which is a private company, but they've been active in the North Sea for some time now, and we'll have a 25% interest in the project.

What will that cost?

The well is AFE'd for about $20 million, and so we'll be paying our prorata share of that.

So it's a much smaller undertaking than the first one?

Yes, it's a fairly modest undertaking compared to the well we drilled last time.

Okay, now you implied you got credit for add-ons, does that mean there actually was a new reserve report?

There's a new reserve report, and it's got $94 oil price in at year-end, so that certainly helps with the economic life of the properties, and as is usually the case, as we now have a year's worth of production from Avouma and South Tchibala under our belt, and so the reserve engineers tend to look a little more favorable on how much of the probable they's willing to put into the proved category. So again, it's kind of a - it's a process whereby we have to convince the reserve engineers to take that 10 million barrel resource and move as much of it - put into proved as they're comfortable putting there.

We had the same issues at Etame. We started out with 15 million barrels at Etame, and now it's up to 55, ultimate recovery, so it's just a process. And unfortunately, as a U.S. reporting company, we have to - we can only report P1 reserves in our 10-K, whereas most of our competitors report P2 reserves, and kind of we get benchmarked against them, but that's just the reality of being a U.S.-based company.

Right, and - okay. Now are you doing much hedging with the new production?

No. We are unhedged. We philosophically, the Board feels this way, we believe that VAALCO probably will remain unhedged, unless we do an acquisition or necessitate to borrow some money, at which time we probably would consider hedging. But we think most of our investors probably have the ability to, if they feel strongly about the price of oil, that they can make arrangements on their own balance sheet to overcome that.

Right, okay. And then finally, this is just a little quirky, but I saw that Exxon was actually drilling offshore wells from an onshore thing using - you know, horizontal going out, I think it's 7 or 10 miles into the - into off the coast of Russia there. Is there any potential for you to not have to do expensive platforms and so forth going forward, or is the geology all different?

Our platforms really are production platforms.

Right.

If Exxon's drilling 10 miles out there horizontally, maybe you could find out what that cost is, but -

Yes, their problems are different. They've got icebergs and the seas freeze up and all that.

Oh, yes, I knew there was different circumstances. I was just wondering if that's some technology that's coming along or whatever for the future for some of these companies that drilling in shallow waters or near the coasts?

It may, but the practical application that we see is that they get better and better with these motors and with ways of stabilizing the drill string, et cetera, that make it all the easier for us to drill our horizontal wells because we complete most of our wells horizontally as well, so I mean the technology trickles down even to people like us.

Great. [Laughter] Well, thank you. Thank you.

Your next question is from Daniel Senneff. Please state your name and what firm you're calling from, and go ahead with your question.

Daniel Senneff with RBC Capital Markets. This 50 Bcf target in your North Sea well, is that unrisked potential and is that gross or net?

It's unrisked gross.

Okay. And how is that prospect developed? Is it seismically defined?

Well it's seismically defined and it's an offset to a shell well, where they actually discovered the gas pool but didn't develop it back in the 70's, and the sand improves in quality the deeper you go in the sand and with the 3D that we have, we think we can get height of that shell well and pull some of those lower sands up into the pay zone, which would then improve the deliverability of the well and hopefully give us a commercial producer. So it's actually an offset of a discovery.

Okay. And what's the assignable risk potential?

Oh, I think we're carrying about a 40% to 50% risk factor on it.

Okay. You said your Etame concession was producing about 22,500 barrels a day in '07. What's production currently?

It's that.

That's current production? Okay. And is there any additional exploration planned in the next six months?

Well, the first well that we would drill may not technically be called an exploration well because it's within the development area of Ebouri, but it's an exploration well because if it works, it triples the size of the field, and that could be drilled as early as this summer, assuming we can get all our partners to agree and get the rig, but we've identified two rigs that are available so we think we can do that.

Okay.

And then the North Sea well will happen probably this summer. Those are the first two wells that we see.

Okay.

But again, after we drill a development well in Ebouri, we will drill but yet another exploration well.

Uh-huh.

Which will be in December.

Yes, there's a possibility on the Ebouri step-out, if you want to call it that, that again to try to drill it this summer, that we are discussing with the Gabonese government to try to persuade them to classify this as an exploration well and not a development well. When you have a discovery, the government assigns an area around it and calls it a development zone, and the activity you undertake within that zone is classified as development. We feel that this is really an exploration well, and are discussing the nomenclature really with the government.

That's for the North part?

North Ebouri.

Okay, got it. Thank you very much.

Yes.

Next question is from John Lubert. Please state your name and what firm you're calling you're calling from. Go ahead with your question.

Guys, how you doing? John Lubert with IL Hedge Investments. I want to kind - I'm kind of new to the company and I'm sure you guys have a little bit more information on this than I do, but I want to try to understand your income tax expense, which was a very high percentage of your operating income. I assume you're paying a lot of taxes to these foreign governments where you're drilling. I want to understand what your target rate is for that income tax expense, and if these taxes that you pay these governments go up when oil goes up, or if it's at more of a fixed rate?

The income tax, the way it works is we pay a royalty off the top, which we do not take in as revenue.

This is in Gabon.

Right.

We pay a royalty off the top, it's 15%, but we do not take that into revenues; most of our foreign competitors do, you should just be aware of that. So we report as revenues the 85 - our net share of the 85% of the production that comes off the concession. Then we're allowed to take up to 70% of that amount to repay capital expenditures and operating costs. What's left is called profit oil, and that's taxed at about a 52% tax rate. So the reason you see these swings from quarter to quarter is if we have an active capital expenditure program, it's immediately deductible in the form of cost oil and it reduces our income taxes.

In the fourth quarter of 2006, we had a drilling rig running and we were installing a platform at Avouma and South Tchibala, and I think it was about a $60 million program that we ran through in that quarter. And so our share of that, which is 28.1%, was deductible in that quarter from income taxes. The fourth quarter we didn't have any major drilling campaign going on, we were building the Ebouri platform but that's running like a million dollars a month, so it's not near the amount of deductions that we would have had in 2006. So that's kind of the way you have to look at it.

And then as I mentioned earlier, if we do something in the North Sea or Angola, that's not going to impact our income taxes because all our taxes are being paid on the Etame concession in Gabon.

Okay, so you get basically half of the increase in oil to your bottom line because you have to pay half of it out to the foreign governments?

Right.

And over time, if this quarter your income tax expense was 85% of your operating income, do you have like a goal - I know sometimes you have more CapEx, sometimes you have less, do you have any concept of where we should imagine that number being?

I think 2008 will look more like 2006.

Okay. And was that more like 50%?

Well, you can see we had revenues of $98 million and we paid $30.5 million in tax, so it was more like 32% of our revenues.

Got it. All right

The reason for that is we have a platform installation and drilling campaign planned, at least three wells and installation of a platform, and that total budget is well over $100 million for the year, for the gross, and our share of that will be 30 something, and so that's going to give us some pretty good deductions in 2008.

Do you guys ever think of adding debt to the capital structure, or do these tax liabilities make it hard to plan for interest expense?

Well, I think we use debt when we've got something to use debt for. We still have a $25 million revolver with the IFC. We do have $5 million borrowed from them. We have considerable cash on our balance sheet, so we don't need to borrow any money at the moment. However, having said that, there are opportunities out there whereby VAALCO could very well at a date in the future use some debt.

You could always buyback stock.

That's a good point. We do have a stock buyback. We bought back 810,000 shares since October.

Great.

We've been in a [quiet] period a lot of the time, that prevents us from buying back additional stock, but I think we spent approximately $3 million, approximately $3 million buying it back, and we've got - the Board's approved $20 million, so we've got $17 million left to go.

Great. All right, well thank you very much.

Next question is from Steve Berman. Please state your name and what firm you are calling from, and go ahead with your question.

Steve Berman, Pritchard Capital. Good morning, guys. Following up on the tax question, Russ, if we ignore the $8.1 million charge for the North Sea, we'll just pretend it didn't exist and put a tax rate on it you would have had, had that not existed, what would earnings per share have been, just totally ignoring that?

They would have been about $0.18 a share, for the fourth quarter.

That's about what I calculated. Another question on the upcoming North Sea well. Are you paying more than 25%?

Yes, we're paying a promote.

So it's similar to the first North Sea well?

Yes.

Okay, and on the balance sheet --

We don't pay any of the back cost for shooting the 3D seismic or any of that stuff. I mean it's just on the well that we're paying the disproportionate.

Right, okay. Balance sheet question or two. The $76.5 million in cash, I assume that does not include the escrow funds?

That's unrestricted cash. We have about $15 million in restricted cash, securing our obligations in Angola, and for the FPSO.

Okay. And --

By the way, we should get about $4.5 million of that or $4.7 million of that unrestricted this year, because they've approved - the Angolan government has approved the acquisition of the seismic, and now that that's approved we can apply to release the $4.7 million that we carry as a current funds in escrow for the seismic project.

Okay. CapEx '08, are you still comfortable with 44, $45 million number?

If we drill that well we referred to at North Ebouri, that would push up closer to 50.

And do you have a final 2007 CapEx number?

Yes. Our net CapEx was 14.5. Plus we had the dry hole, so if you add the two together you're up a around 23.

And are you - the North Sea well, the first one, are you done taking charges for that? Was that all taken in the fourth quarter, or is anything running over into Q1 '08?

No, it's going to run over the first quarter of '08, probably about $4 million, $4.1 million; is that right, Russ?

Yes.

Yes. And while we're there, whether it works or not, at this stage it's impossible to tell, but we've had an inquiry from an unnamed, well we're not going to tell you who it is, but an operator that has some interest nearby, and they have contacted us, at least preliminarily, to see what - the availability of them taking over that well, and those conversations will - have not really started but the inquiry is there, so there is a real possibility at least that we may be able to recognize the revenues from that.

Yes, it was a discovery, by the way. It just wasn't as big as everybody thought it was going to be, and with the infrastructure that was not nearby, it wasn't economic to develop. But if this new operator comes along and develops a discovery they have a mile or two away, and wants to tie our well back to that, then that would work.

Okay, now, in terms of - you know, you talked earlier about one knock on the economy being not a high 1P number, there's probably also concern out there about, at least right now, 100% of your production being offshore Gabon. I'm just wondering with the balance sheet strength you have, the liquidity, the cash flow you're generating in an $100-plus oil environment, why not just go out and buy some diversification instead of some high-risk exploration? I mean, what are your thoughts there?

We may very well do that.

Okay. Sounds good. I'll let someone else go, thanks, guys.

Yes.

Our next question is from David [Sittusi]. Please state your name, what firm you're calling from, and go ahead with your question.

Hi, David Sittusi calling from [CRFC] New York. I have a very, very quick question. I would like to know if you are planning on meeting with Nanes Delorme Partners LP in the upcoming weeks?

I said earlier that we weren't going to comment on the content of that letter, so I'm going to leave it there. No comment.

Okay, I'm sorry. Thank you.

Next question is from Ben [Sinnock] from MDJ. Please go ahead.

Hi, guys, good morning. I guess a little bit like the sort of previous question, as a shareholder of the company, I think we wouldn't disagree with you that the stock price is - doesn't probably reflects the prospects of the company, and I'm curious you mentioned a little bit about the stock buyback. Are there other concrete steps that you guys will take, irrespective of what Nanes Delorme kind of turns out to be, to generate some kind of shareholder return over the next year or two?

Well, we can't guarantee anything, but I think that we can spend an extraordinarily diligent amount of lining our ducks up for this drilling program that we're about to undertake. We have high confidence in it, we believe that there isn't a company of VAALCO's size out there that has the drilling prospects available to it, and the quantity of reserves that we could uncover. I will caveat that. We are in the oil business. We will drill some dry holes, but the prospects for VAALCO I believe is superb, and you mentioned our stock buyback program, I think it's fair to say that we will continue with that.

Okay, thank you.

Next question is from Jamie Wilen. Please state your name, what firm you're calling from, and go ahead with your question.

Wilen Management. The dry hole in the North Sea, after the first quarter will that have been written down to zero, or are there some residual things because it's still --

No, we're taking the whole charge.

Okay, beautiful. And in Gabon, you mentioned that - whether the government declares it a developmental well or an exploratory well; why does that matter?

Well, we have an obligation to drill one exploration well by July of 2009. That's under our current exploration license. And in the past, three - the first four wells we drilled on Etame were designated as exploration wells, so there's precedent where we could request that this appraisal well be classified as an exploration well. It's in the government's interest to do it because, if that works, we have additional development wells that we can drill off the Ebouri platform. We have three slots on that platform, so we could drill two more development wells off that platform, and that's in their interest because that going to mean more royalties and more profit oil for them. So the key is we have to drill one exploration well that the government calls an exploration well by July of 2009, and if they'll let North Ebouri be that well, that's great. If not, then we may have to [show] the well, then we might have to drill something over here that is not as attractive as this. Now we don't want to do that, so we would probably end up doing both, but we'll have to see how the government reacts.

Drilling in the North Sea obviously is rather expensive. What does it cost you to drill onshore/offshore Gabon, a well, versus what a North Sea well costs?

Well, the gas well we're getting ready to drill and a well in Gabon are comparable, because they're both jackups. The well we drilled with Bo Valley was a semisubmersible, and those things as you know run high 300s a day for a rig, compared to jackups are 200 a day kind of thing, so - but a North Sea jackup is not a whole lot different from a Gabon jackup. And then onshore, you probably are looking at 40,000 a day as opposed to 200,000 a day, so it's maybe 20% as expensive, and the wells onshore are shallower than they are offshore.

$5 million.

It's a $5 million well as opposed to a $15 million well.

Okay.

And most - not most, but a good portion of your money is building whatever road and location you need in the jungle in order to get at your prospect. We're fortunate in that the first onshore prospect is going to be on an island, and there's a dock there that we can load the rig on to and sail it out to the island, so we're not going to have to build any roads. So that will actually be probably a fairly inexpensive well relative to if you had to build a 2-mile road through the jungle to get to it.

Got you. And Angola, how expensive will that be?

Probably be more like the North Sea, semisubmersible, it's in 400 feet of water, and it'll be pretty stout well. But it's a big prize.

Absolutely, the prizes seem bigger for the cost in Gabon than they do elsewhere, and you know the territory better.

Yes.

Lastly as far as liftings go, I'm still not quite sure why it's so sporadic, and is there a rhyme or reason to why they only pick up 100 here and 300 there, and how much inventory is left in the loading tank afterwards? What's the basis for how they choose to - and you're doing it a half million barrels next week, why is it done like that?

Well, we have a new buyer this year, it's Shell, and Shell, the first few months of the year, lifted some pretty small cargoes because they were trying to feed our crude to some new refineries to see if they couldn't improve the marketability of the crude. So I mean, believe it or not, that 138,000-barrel lifting they sold to themselves, because they wanted to try the crude out in one of their refineries. So I have to say that that whole crude oil trading marketing world is somewhat murky, and why they only want 300,000 one time and 600,000 the next, I think is purely a function of who they line up for buyers out there, and one buyer one month may need a bunch and another month they're running, they're trying to make gasoline not fuel oil, so they want less of our crude. It's that kind of a thing.

And it's tanker availability also, what tankers Shell may have offshore Africa, they may have filled up someplace else or filled up half the tanker, three quarters of the tanker, and then they stop by you and take X number of barrels to fill up the rest of it. It's unpredictable, you're right, and it's difficult to absolutely ascertain how much they want and on what date.

But they have agreed in the contract to lift everything we produce in 2008.

Yes.

It may come can in 15 liftings, it may take 18 liftings, but they're going to lift it all.

Okay, and do we pay a fee each time they come by or...?

Occasionally, we have to rent a standby - a second standby vessel. We try to share, there's another operator that's about 10 miles away from us that has a vessel, and we have a vessel, and if their vessel is not making a run to shore for supplies, or vice versa, then we share. If, however, the vessel is not available to share, then we have to spot charter a vessel, and those things run a couple hundred thousand dollars of lifting kind of thing.

Got you. And lastly, as I look at what you - you said you're in the fourth quarter, if you didn't have the dry hole cost, it would have been $0.18. If you don't - excluding all of those extraordinary - the dry hole costs or whatever, given the increased volume because you're producing at a greater rate now, given the increased pricing, I would assume without external charges you'd be looking at $0.25 to $0.30 in the first quarter. Is that a good ballpark number, excluding those things?

As long as Shell doesn't play games and delay a lifting.

Got you. All right, thanks, appreciate it. Nice job.

Next question is from Julian [Balcany]. Please state your name, what firm you're calling from, and go ahead with your question.

Hello?

Yes, we're here.

Yes, you know, I understand that you don't want to address, you know, the letter in this conference call, so I believe we should have a conversation later on, and I just would like to state that I would be very happy to have an opportunity to further discuss with you and the rest of the Board our letter.

Good. Thank you.

We have a question from John Lubert. Please state your name, what firm you're calling from, and go ahead with your question.

John Lubert from IL Hedge Investments again. Just want to try to understand on a follow-up, how much capacity do you have to store oil before Shell comes to pick it up, and has - I guess that has to do with these storage boats? How does that work? And do you get the price when they pick it up or when it comes out of the ground?

We have 950,000 barrels of storage capacity. Actually, we have a little over 1 million barrels but we need 80,000 barrels for [ballast], so the biggest cargo we can deliver in a single shot is 950,000 barrels. And the price we receive is the average price of Dated Brent for the month in which it's lifted, less a negotiated discount, they were the high bidder, and I can't tell you that number exactly because it actually gets negotiated between the government and Shell, Total, and some other operators, so it moves up and down $0.50 a quarter kind of thing, but it's a couple dollars discount off Dated Brent, is what we typically receive.

Okay.

That's the average for the month in which it's lifted.

And the wells you're looking at in the North Sea and Angola, are the royalty rates there comparable to Gabon or are they a better deal for you?

There's actually no royalty in the North Sea.

Okay.

There's just a 50% income tax, but you have normal depreciation and depletion, deductions, and et cetera. In Angola, it's pretty - it's similar to Gabon. There's a royalty and then there's a cost oil factor and there's a profit oil factor. The difference between Angola and Gabon is their profit oil factor increases as your rate of return increases over time. So early in the project you get a very favorable profit oil split, I think we get to keep like 70% of the profit oil as opposed to 48% in Gabon, but then once you get your rate of return up over 20-25%, it flips way around the other way and you only get 30% of the profit oil, so -

So you get a profit early.

Right.

Last question. If you were to hedge your production, would you pay your royalty and tax on the hedged price that you receive or on the --

No, hedging has to be done totally off with a third-party institution, and that's the problem, is you can get whipsawed around, and you may be selling your crude at $90 or whatever, but you may be paying $20 million to this third-party institution because, you know, the price of oil spiked up that month, and so it's very volatile, and that's one of the reasons we've kind of avoided it, because that had - the government doesn't recognize hedged prices, they recognize the market price, and that's what you'll pay your taxes and royalties on.

I want to make sure, if that was in the contract it might make sense, but without that in a contract you put yourself in a really bad situation by hedging.

Exactly. You could be paying royalties on $120 oil or something, and it'd be hedged at 90 and nothing you can do about it.

That's all I have. Thank you.

Our last question is from Kenneth Pounds. Please state your name, what firm you're calling from, and go ahead with your question. Kenneth Pounds, go ahead. At this time, there are no further questions.

Okay. Well, thank you all very much. We appreciate you attending our meeting, and we'll enjoy hearing you and seeing you at the next meeting. Oh, yes, our Annual Meeting is coming up, June 11 - early part of June, but it's posted on our website, and certainly we welcome you all to Houston. Okay, thank you all.

Thank you, ladies and gentlemen. This concludes today's teleconference. You may all disconnect at this time.