Ladies and gentlemen, thank you for standing by. Welcome to the First Quarter 2014 Earnings Report Conference Call. At this time, all participants’ lines are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given at that time. [Operator Instructions]. As a reminder, today’s call is being recorded.

I would now turn the conference over to our host, Chief Executive Officer, Steve Guidry. Please go ahead, sir..

Thank you, Rose and good morning everyone. Welcome to VAALCO Energy’s first quarter 2014 earnings conference call. On the call with me today is Russell Scheirman, our President and Chief Operating Officer; and Greg Hullinger, our Chief Financial Officer.

Before we begin our business update, I’d like to take a bit of time to congratulate our Chairman, Robert Bobby Gerry on his decision to retire after 17 years of outstanding service.

Effective June 04, 2014, Bobby will be retiring from his duties as Chairman of the VAALCO Energy Incorporated, but has agreed to remain part of the VAALCO team as a valued non-executive advisor and chairman of [inaudible]. We want to thank Bobby for his dedication and his many important contributions about VAALCO Energy’s success during his career.

Bobby’s leadership has certainly helped to create significant value and we wish Bobby the very best in his role as chairman of an advisor to the board and to the management team. So thank you very much Mr. Chairman. With that, I’d like to begin this morning by asking Greg Hullinger to cover our cautionary statement..

Thank you, Steve and good morning everyone. Thank you for joining us on the call today. During the course of this conference call, the company will be making forward-looking statements. We caution you that any statement that is not a statement of historical fact is a forward-looking statement.

Forward-looking statements are those concerning VAALCO’s plans, expectations future drilling and completion activities, expected capital expenditures, prospect evaluations, negotiations with governments and third parties, reserve growth and other operations.

Statements made during this conference call that address activities, events or development that VAALCO expects, believes or anticipates will or may occur in the future are forward-looking statements.

These statements are based on assumptions made by VAALCO based on its experience, perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances.

Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond VAALCO’s control. Investors are cautioned that forward-looking statements are not guarantees of future performance and that actual result or developments may differ materially from those projected in the forward-looking statements.

VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Accordingly, you should not place undue reliance on forward-looking statements.

These and other risks are described in yesterday’s press release, titled forward-looking statements and in the reports we file with the Securities and Exchange Commission, notably the 2013 Form 10-K filed with the commission on March 13 of 2014. Please note that this conference call is being recorded. Steve, back to you..

Thank you, Greg. We continue to see measurable progress on our projects in Gabon as well as Angola and Equatorial Guinea some in also but was a near perfect fourth quarter 2013, which was by four liftings in the quarter. We were anticipating and in fact experienced, corresponding reduced revenue in the first quarter of 2014 which had only two lifting.

Our third lifting actually occurred on April 1st one day two late to be booked in the first quarter. Combining this with additional exploration expense stemming from the results of the Dimba well which unfortunately encountered hydrocarbons in economic quantities and uneconomic quantities resulted in significantly lower first quarter income.

As production from the Etame Marin Block continues to perform very well, we remain confident in our ability to deliver our targeted operating cash flow and income for the 2014 calendar year. I’d like to now update you on what’s happening in our company across our portfolio beginning in Gabon.

Our expansion project in Gabon continue to progress as the platforms are nearing completion. While Russell will be reporting on the projects in more detail later, I do want to say how pleased we are to announce that our first of the Etame jackets actually sail for Gabon earlier this week.

The projects remain on schedule and on budget, and will be operational in the fourth quarter of 2014. We’ve also contracted with Transocean to supply the jackup rig Constellation II, to drill the next six development wells slated to begin drilling in October this year.

VAALCO has also been working to progress our exploration growth opportunities in Angola and Equatorial Guinea. I’m pleased to announce that we have reached preliminary agreement with Sonangol E.P., the National Concessionaire, to extend the Block 5 license to December 2017.

This agreement will require VAALCO and our partners to spud our first commitment well in the fourth quarter of 2014, and drill our second commitment well by early 2016. This agreement is in the process of being ratified by the Angolan government.

In addition, we have contracted with Transocean to supply the semi-submersible rig, Celtic Sea, for the purpose of drilling the 2014 post-salt well on Block 5. The rig contract has been submitted to Sonangol E.P for approval.

In Equatorial Guinea, we’ve met several times in the first quarter with representative of GEPetrol, the operator of Block P and has progressed our shared operator ship arrangement which has been very well received.

We’re looking to meet with our partner again next week and with the Minister of Mines and Energy later this month to present our arrangement. If accepted, this of course, will clear the path for being able to drill two wells in Equatorial Guinea in the 2014-2015 timeframe.

Last quarter, we reported on our efforts to supplement our exciting exploration growth, with an effort to acquire new opportunities in West Africa which will provide balance to our growth portfolio.

That effort continues as we are reviewing discovered, undeveloped shallow and/or onshore resource opportunity across all of West Africa from Cote d’Ivoire to Namibia. We’ve been meeting with companies both IOCs and indigenous companies, in an effort to forge new partnerships and jointly pursue new opportunities.

We are in fact however, being very patient to ensure that any acquisition we might pursue matches our proven competencies and skill set and presents real value growth potential. With that, I’ll pass the call over to Greg, to discuss our financial results in further detail..

Thank you, Steve. I will be providing an overview of the key financial information for the first quarter of 2014 that we reported yesterday in our 10-Q filing with our SEC and the press release. The company reported a net loss of $7.0 million or a negative $0.12 per share for the first quarter of 2014.

This compares to a net income of $7.2 million or $0.12 per diluted share in the first quarter of 2013.

The net loss reported for the first quarter this year is attributable to two factors; the impact of the exploration dry-hole cost from the Dimba well offshore Gabon, that we drove during the quarter and our timing of the third lifting that occurred in 2013. I’ll first dive into the revenues lifting and production information.

Revenues in the first quarter of 2014 of $28.1 million were 36% lower than the same period in 2013. VAALCO’s share of the lifting during the quarter totaled approximately 257,000 net barrels from lifting that occurred in January and February of 2014.

As Steve mentioned, the third lifting of the year occurred on April 1, 2014, so the revenues for our share of lifting will be reflected in our second quarter 2014 financials. Had the third listing occurred one day earlier, our revenues would have been higher in the first quarter by approximately $8 million.

I’d like to mention that beginning with our May lifting, we are operating under our new crude sales contract where we have more control over nominating the size of the liftings and the lifting date.

By comparison, VAALCO’s share of the lifting from the first quarter of 2013 totaled approximately 397,000 net barrels or about 35% higher than the Q1 2014 lifted volume. The average price we received for the first quarter lifted volumes was $107.97, $2.10 lower than the price received in the first quarter of last year.

Keep in mind, that quarterly revenues are highly impacted by the timing and size of our crude liftings. A key measure is to understand our production profile. Production for the three months ended March 31, 2014 was approximately 335,000 net barrels as compared to 360,000 net barrels for the same period in 2013, a 7% decrease.

80% of this decrease was associated with a scheduled maintenance shutdown of the FPSO lasting about five days which caused a complete shut-in of all production from the block.

The remaining of the production decreased resulted from the rig move from the exploration location to the platform which caused the production from that platform to be shut-in for a couple of days. To summarize the revenues, liftings and production here’s my quick recap when comparing Q1 2014 versus Q1 2013.

Revenues were down 36%, lifted volumes were down 35% in direct correlation. Average prices of crude was down 2%, production was down 7% mostly attributable to the planned FPSO maintenance, and quarter two will benefit from the lifting that occurred on the first day of the second quarter.

With regard to the second factor that drove negative net income in the first quarter of 2014, exploration expense of $11.3 million in the quarter was comprised primarily of the Dimba well dry-hole cost.

At last quarter’s conference call, I reported that we rode off to Q4 2013 costs that were incurred on this offshore Gabon well totaling $1.9 million and the remainder $11.2 million was going to be recorded in the first quarter of 2014.

The actual amount of the well dry-hole costs reported in Q1 2014 was $10.7 million, slightly less than my earlier estimate. It is easy to see the significant financial impact of an unsuccessful exploration well on our income in a quarter.

In this case, the dry-hole costs of $10.7 million plus $0.8 million of associated undeveloped acreage expense impacted the first quarter negatively by $0.20 per share. Now I’m going to move on to other key financial components for the quarter.

Operating income was $0.7 million in the first quarter of 2014 compared to $21.5 million for the first quarter of 2013. Production expenses for the 2014 first quarter were $9.7 million compared to $8.4 million for the 2013 first quarter.

The increase is attributable to expense incurred on the Avouma 2H well where we replaced the submersible pumps or ESPs at a cost of approximately $3.2 million. Exploration expense in the first quarter of 2014 was $11.3 million as mentioned earlier, and that compared to $6.1 million recorded in the first quarter of 2013.

Income tax expenses for the first quarter of 2014 were $6.1 million compared to $14.2 million in the same three month period in 2013.

The decrease in income taxes reflects the impact of the lower volume accrued lifted during the quarter and a higher cost account which result in a higher percentage of barrels allocated across all barrels versus profit oil barrels and again oil barrels did not attract income tax.

Cash and cash equivalents including restricted cash totaled $93.7 million at the end of first quarter 2013. The reduction from our cash position at the end of 2013 is largely due to partner receivables totaling $41 million that were outstanding at March 31, 2014.

These amounts were substantially received in April 2014 and our cash balance today is significantly higher. The company has not drawn down any debt against our new $65 million IFC credit facility that we completed in the first quarter of this year.

VAALCO’s capital expenditure budget for 2014 remains at approximately $117 million, the same number we reported at last quarter’s conference call. Also as previously mentioned, we recently invoice Sonangol’s E.P our new working interest owner in Block 5 Angola for over $8 million pertaining to unpaid partnership share cost dating back to 2009.

Once received, this amount will be recorded as net income in our 2014 financials. With that, that concludes my review of VAALCO Energy’s Inc. first quarter financials. Russell Scheirman our President and Chief Operating Officer is up next to provide you with the operational update.

Russ?.

Thanks, Greg. I’d like to update everyone on our ongoing activities at Etame, our onshore Gabon Mutamba project and Equatorial Guinea and then also have some new progress to update on our Angola activity. Since our last call, we successfully completed a pump change at the Avouma 2H well.

We were also able to secure an additional rig slot for the Ben Rinnes rig. So we’re currently re-drilling the South Tchibala 1H well which experienced recent failure a few years back.

This will allow us to add a fourth producer at the Avouma South Tchibala platform and should help to mitigate the client as we await the installation of two new platforms later this year. We will be drilling six new development wells on these two platforms at Etame in the Southeast Etame area during late 2014 and 2015.

And we’ll also drill dry gas wells to provide fuel gas as a source of the Etame complex in the future, eliminating the daily use of diesel for power generation. During March, we completed a five day maintenance shutdown, the FPSO to repair facilities and piping.

We successfully restarted the Etame complex and production is currently running at about 17,500 barrels per day gross which is about 4,300 net barrels a day to VAALCO. Two platforms for Etame and Southeast Etame North Tchibala remain on schedule, with fabrication of the platforms at Gulf Island fabricators in Honolulu, Louisiana.

As Steve mentioned the first jackup was loaded on to a last week for transportation to Gabon to installation between June and July and it will be followed by the next jacket which is loading next week.

Our installation contractor Emas also has completed pre-laying the pipelines in Gabon to connect the new platforms, the FPSO and that the work was completed during the first quarter. Emas is bringing a new heavy lid vessel called the Constellation which will arrive in the field in June to install the two jackets.

They will turn in September to install the two decks on to those jackets such that we can begin drilling in October. Our total investment in this project will be about $133 million at VAALCO, most of which will be spent this year and in 2015.

Our goal from these two projects is to maintain production near to or above 20,000 barrels per day through 2016. During the first quarter, located a drilling rig for the platform project and we recently signed an agreement to utilize the Transocean Constellation II rig.

The rig’s currently operating at Gabon for another operator which will minimize the mobilization time and cost of the rig. It’s anticipated to be released to us in October of this year which is right on time, with our platform installation schedule. It’s a modern 400 foot jackup and will be ideal for the drilling program that we’ve planned.

Preliminary front-end engineering, design work has been concluded for a sweetening facility. You may recall that in 2002 two of the Ebouri wells began producing H2S and were suspended. In addition, we recently, by preliminary testing it appears that the Etame 5H well may be producing low levels of H2S.

The 300 barrels per day well have shut in while we work to confirm the field testing.

Laboratory confirmation of the H2S will not be available until the third quarter this year, but meanwhile we are commencing full front-end engineering design of the sweetening project to reach final investment decision by year end 2014 or early 2015, with the facilities in place by early 2017.

Moving onshore, we filed an exploitation interior around the Mutamba Block N’Gongui discovery that we announced last year. We remained in discussions with the government over the approval of this development area. There are some issues over some that they are seeking to oppose over the consortiums.

We’ve exchanged drafts for the production sharing contracts extension with the Gabonese administration, and hope to conclude negotiations on it in the near term so that we can borrow a development plan. We envision telling the discovery back to the field which is a operated field about five miles of N’Gongui.

We are also negotiating the extension of the exploration area with an initial three year term for that block. Moving to Equatorial Guinea, we own a 31% interest in the provisional development area of Block P offshore Equatorial Guinea.

The block is operated by GEPetrol a national company who have a 58% interest and there’s two other partners who each have about 5%.

There is a 2005 former Devon discovery known as Venus located on the block at a water depth of about 800 feet and there are two other prospects that we would like to explore and we plan to commence two well drilling program after we worked out arrangements with GEPetrol for VAALCO to assist its operator.

They’ve been operator now since 2007 without any real progress on the block. We entered last year so we’re hoping that we can get this thing center.

In that regard, we proposed a joint operator model with GEPetrol which has been well received by them and the Ministry of Mines, and we’re currently making plans to implement their organization so that we can begin the planning process and as part of the mean to commence drilling.

We actually have drilling personnel on the ground in [inaudible] they’re scouting our drilling yard and meeting with service companies who we’re supporting on this drilling project. Finally moving to Angola, we’re currently under a two year extension and it expires in November 30 of 2014.

And since our last call, we’ve had some technical workshop with our new partners Sonangol E.P. and we’ve all agreed on our first prospect to drill which is a post-salt test named Kandeli[ph]. It offsets an old discovery.

As Steve mentioned, we’ve also negotiated an extension with the government which we’re in the process of documenting the extension calls for drilling of one well this year and second well by early 2016. A full details about extension will be released with the documentation is finalized and we’re confident that it will be successfully concluded.

We’ve also tender for a drilling rig for this 2014 well and we have contract with the Transocean Celtic Sea which is a semi-submersible rig that should be available to us in October.

The contract terms have all been agreed to and initialed and it’s been submitted to Sonangol for their final approval Sonangol government, Sonangol for their final approval.

For the second well in anticipation of it, we’ve licensed a 1,050 square kilometer seismic survey in the deeper portion of our block to evaluate structures that we see on two even or similar to ones that we drill by Cobalt’s this year and which led to their Kwanza Basin discoveries.

This seismic is being merged with our existing 1,175 square kilometer survey that we have over the center of the block and we expect to have that all processed to pretty depth migrated volume by the end of this year. Completion of that process will allow us to high grade the best remaining prospect for our second commitment well.

So with that, Steve I’ll turn it back to you..

Okay. Thanks, Russ for that comprehensive review. So overall, we are very pleased with the project progress we’ve made in the first quarter of 2014. In particular, we’re excited to have contractors for the rigs to begin our drilling campaign in Gabon and Angola, and have seen our first jackets set sail for Africa.

We are – with our production having return to normal levels after the March turnaround, we are very confident that we will see strong second quarter performance.

We also intend to continue to evaluating opportunities specifically the discovered undeveloped resource opportunities throughout West Africa that we believe have the potential to expand our footprint and significantly add to our reserve base. So once again we’re excited about our direction.

We think that VAALCO is moving in the right direction and the increasing rate of progress that we’re making on projects we find that particularly exciting. So with that, we’ll open it up to questions.

Rose?.

[Operator Instructions]. Our first question comes from the line of Brad Heffern with RBC Capital Markets. Please go ahead..

Good morning guys. I wonder if you could a dug a little deeper into the new H2S potential issue.

Will the sort of engineering work that you’ve already done cover this new well producing H2S as well and potentially more of them? And also, I think that you had discussed in the past the potential that the H2S was migrating through the reservoir and I wonder if you could talk about if this is the closest well to the old well that we’re producing H2S and how you see that sort of theory?.

This is Russ. Actually the closest wells of two Ebouri wells is our third Ebouri well which continues to produce with very strong amounts of H2S. It’s about a kilometer away from those two wells that we shut in and that well has been producing now for almost two years, since those other two wells started producing H2S.

The Etame 5H well is like 10 kilometers away from those two wells. So we are thinking this may be some sort of phenomenon associated with very high water cut wells.

The three wells that have produced H2S are the three highest water cut producing wells that we have in the field and by the same token the three lowest oil producing wells that we have in the complex.

So we’re setting that we hired a couple of experts if you will, Weatherford and a company called QRI that are looking at this phenomenon to try and help us understand what’s going on.

But there’s a clear solution and that is just to process the water and the oil that comes off of any wells that makes sour, and it’s been done before in Gabon actually not had a field that was producing H2S and it basically evolves treating with gas to the H2S convert soluble and gas draw that H2S off and then you have good quality oil that you can shift to the.

So front-end engineering design that we’ve been doing was trying to decide where to put this sweetening facility whether it should be centralized at Etame or whether it should be up in Ebouri.

And right now we’re looking at probably centralizing it at Etame so that we can move any oil, but give sour to that facilities treated and then ship it [inaudible]..

Okay. Got you. And can you talk a little bit about say this well doesn’t proven sour what the incremental cost is over the treatment facilities that you’ve already designed.

Does that need to be expanded or is it just simply drilling the well bores?.

No we don’t’ have to drill through well boroughs. We did our front end engineering design anticipating that this might become a more widespread phenomenon and you’re basically talking about another platform along the lines of what we’re doing at Etame and Southeast Etame lifts and different facilities on it.

A tower so that you can put the crude in the top and works its way down this tower mixing with the sweet gas and take out the H2S. So you’re looking at investment like that..

Okay. That makes sense..

I might just add Russ mentioned there was a need for another platform that’s one platform the same platform that we were anticipating would be necessary at Ebouri this is that same platform. So the suggestion that Etame 5H might be producing H2S does not require yet a second platform. It’s that same one we’ll just move it to a more central location..

Okay. Great.

Moving over to Angola, I was curious what’s your confidence level is getting a rig by the time that the new exploration date hits? Is there enough whereas if that rig doesn’t get released in time would you be able to find another one and how you would see that playing out if you weren’t able to drill the rig before November 30th?.

Well we have a rig and it is expected to come to us in October. It’s currently working in Angola for another operator.

I just feel like if it were to be delayed by a month or so, we can work our way around that there’s actually line in a proxy shared contract that says that as long as you spudded the well by November 30th you have some extra months to finish the well this kind of thing and we actually have worded the language saying that we will commence the well by November 30th, not complete the well by November 30th.

So we feel very confident that we’ve got things under control there..

And about how many days do you think that that drill time is going to be?.

About 40 days..

Okay.

And then last one for me, just on this new oil contract, can you discuss if there is any sort of change in what pricing is going to look like? And does this mean that you’re not going to have this problem across the [inaudible] again?.

The new model that we are testing is one where we have contracted with we’ve actually contracted with Vitol and they are agents.

So we will be dealing directly with the buyer we will know who the buyer is and we are now in-charge of nominating what dates we want to lift, whereas our old contract model was they quoted us a fixed price against [inaudible] and we didn’t really know who the buyer was, and we didn’t know what prices the buyer was paying Robby plus X and we didn’t know if Mercuria or Vitol was a previous seller for us whether they were getting Robby plus $0.50 and pocketing $0.50 so whatever.

So we’re now pay a flat fee and its pennies ago through the agent and then we will be soliciting bids from around the world for our crude and then we’ll take the highest bid for each cargo.

So we’re hoping that this will allow us to better control and we won’t have this flip from March 31 to April 1 of $8 million of revenues goes away we reported $7 million loss of everybody thinks we had a bad quarter would be it would have been a fine quarter if we had a lifting at March 31st..

Okay. Thanks guys..

Thank you. [Operator Instructions]. Our next question comes from the line of Kenneth Pound with Castleberry. Please go ahead. Kenneth Pound your line is open..

Hello gentlemen..

Good morning, Kenneth..

Yeah I wanted to double check something you said. You said that your portion for the investment for the new rigs to drill the six wells is 133 million over two years.

And for that money you are basically just your goal is to bring production back up to 20,000 barrels?.

They will be north of 20,000..

Yeah, because it seems like an awful lot of money for fairly small incremental increase, are there other benefits too these six new wells because of production to grow or give you more information it just seems like awful large investment?.

Kenneth this is Steve Guidry. Thanks for the question. The wells I’m not sure of the well cost is actually $7 million apiece so the six wells the net to VAALCO its $42 million for the well. The number you heard was the total investments that includes the platforms.

Now recall the platforms are eight flat platforms and so setting these platforms it sets us up for the potential to drill additional developmental wells in the future. So there is a kind of a fixed cost early investment with the platforms but the wells themselves are $42 million net to us..

Okay. That makes more sense. All right.

Since you’re having all these marched a lot how many additional wells are you looking at years out?.

That’s difficult to say our approach to this will be to drill the initial wells monetize the production bring that into our reservoir stimulation and see what the reservoir stimulator suggests might be additional potential for us to grow in the future. So it’s hard to say at this point..

But keep in mind that the Southeast Etame North Tchibala platform is drilling in to two new reservoirs, one of them is Southeast Etame where we drilled a successful exploration well couple of years ago and so that will be a new Gabon development.

And then the other area that we are going to be developing is called the North Tchibala field and that is a very tall field and this will be our first time to try and develop within tall field. It’s got large volumes of oil in place we’re not just sure how the recoveries are going to be.

If we give a little bit of good look we can drill a bunch of well in the North Tchibala and that would make for very exciting development..

Okay. That’s good to know.

I guess the last thing is what are the dynamics with your partners now? I know that that’s changed a little bit over the years?.

We’ve been along fine with our partners. We have two large partners Sinopec formerly Addax who have about 30% we have about 30% and then we have Sasol that has about 30%.

So without going into specifics, we have one partner that’s very aggressive and one partner that’s little bit conservative and we’re probably in the middle and we seem to work things out and they’ve [inaudible]..

What are the long-term plans of the FPSO then if you’re looking for five years from now having a lot more wells from the new platform so you can come up against capacity problems again right?.

Well the way we address that these new platforms have the ability to knock out all the water. So they all will be doing is delivering oil in FPSO, so that we don’t crowd out any of our oil capacity with a bunch of water coming from these new platforms.

Now the oil capacity is limited to 25,000 barrels of oil a day, we’re currently at 17,500, so we’d like to get up as close to 25,000 as we can And then we can handle another 8,000 or 9,000 barrels of water a day from the wells that are actually tied to the FPSO.

So we’ll be in pretty good shape in terms of being able to max out that FPSO with oil and not getting crowded up by bunch of water..

Okay.

Finally, you said that you have a dry hole expense is that the first one that was actually offshore that was dry hole and what’s the kind of postmortem on that?.

No that wasn’t our first dry hole offshore Gabon..

Okay.

We had some others we actually had another one called the – that was dry. It’s the oldest issue, you win some you lose some. I think we probably have a better than average track record of successful wells, but lately we have a couple of dry holes..

And I would add Kenneth that typically on the Etame Block and exploration, it’s the structure that is the unknown quantity when you are drilling this exploration wells. Our last exploration well, the Dimba well we actually did find significant structure at this location.

But unfortunately what we found was the thinnest Gamba sand that we ever found on the Block. So it was perhaps the paleo high that was eroded or at least provided a very thin Gamba deposition and it was hydrocarbons but it was just very thin unfortunately..

Okay. Thank you very much..

And I would make another comment is, these exploration wells are cost recoverable.

So we do get to take the cost oil to recover the cost of each wells and we move some profit oil so they are not free obviously, but if you are going to explore you want to do it when you have an active cost account, an active production so to actually reduce the actual cost of these wells..

Thank you..

Thank you. Our next question comes from the line of Neil Nelson with DERS Group. Please go ahead..

Can you talk about the South Tchibala well where the casing failure occurred? And when that well will come online and will that volume replace the loss per production on Etame 5H well?.

They actually have the warned ESPs this week so we should be completing that well and be off it by the middle of this month and turning it on in the second half of this month. The production from that well will more than replace the 5H production. It should be we’re hoping to an excess of 1,000 barrels a day on that well..

And when you talk about the two new production platforms, are there and the infrastructure cost of getting them installed, are there any of those aspects that go toward cost oil in the sense that you now have eight slots on those platforms? And that you start your drilling program you’ll be using those platforms does anything attribute to cost oil from the platforms from sales?.

Yeah, I mean that’s the beauty of the cost account because we for example, if we spent $20 million this month on the platforms that comes back to us literally the next month in the form of cost oil.

So that’s why you’ve seen our cash skate at a pretty constant level just account receivable partners was kind of loopy thing, they vacate on time we would have another 40 million of cash where we’ve been saving here 120 million in unrestricted cash.

Literally, you pay the money to construct the platforms and it comes back to you in the form of cost oil the next month and you’re not seeing us through all our cash it’s $100 million because we’re collecting the cash back in the form of cost oil. And you can collect it as you spend it you don’t have to wait until the platform comes on production..

And on the Angola target that you’re selected jointly to drill, of that target is not one of the larger if I recall, potential reservoir but being post-salt and being close to the prior exploration well, a discovery well.

Does that give you a balance of the highest probability of success?.

Yeah Kenneth – sorry Neil this is Steve. It does. This is a post-salt test it definitely has the characteristics of being one of our higher probability of success wells.

We place the probability of success at one and two in terms of finding hydrocarbons and at the same time, it’s a relatively low cost well compared to the pre-salt wells that are likely to be drilled in the deeper water portion of the block. We anticipate right now that Kandeli[ph] is in the $30 million to $35 million range growth..

And we’ll be paying for half of that..

Okay. Okay. The next question is with regards to you have a timeline in your presentations and you’ve actually showed that it’s a relative timeline with hard dates on it. But you showed that you actually had the – exploration well for Guinea in Block P has earlier in schedule than Angola.

Is the rig that you are contracting with have any optional slots on it that would give you an opportunity to drill in Block P yet this year using that same rig if you meet agreement?.

Neil this is Steve again. The presentation actually has the Angola well ahead of the Block P well the first Angola well ahead of the Bock P well.

So it’s likely just an occurrence is in the same order is what we had in the presentation I think, but having said that there’s two different rigs and it’s unlikely we would use the same rig to drill both wells..

Okay. That concludes my questions. Thank you very much..

Thank you, Neil..

Thank you. There are no further questions at this time..

I want to make one other comment just getting back to a previous question about the Etame 5. I just want to remind everyone that the Etame 5 is 300 barrel a day well, and when we detect it they H2S when we use some rudimentary field measurements to test that, we shut the well in.

It’s a 300 barrel day well but I want to remind everyone that, the Etame well has produced for over 12 years without any H2S production.

And we are yet to confirm in that well that in fact we are producing H2S and what we’re doing is we’re mobilizing laboratories testers in order for us to open the well back up and get some tests to ensure that in fact what we have is H2S at that well location.

There is a chance you may hear us in August talking about us having confirm that in fact there is no H2S. So we still have some work to do is the point to confirm that. And as we said earlier, the fortunate thing here we got a jumpstart on this. We’ve been working with designing the H2S treating facility for a couple of years.

And so what this really represent is an incremental modification to a project that was already conceptually designed and it upscaled it slightly and that will be a minimum cost. And we can’t talk about cost yet, because that’s what FEED’s all about.

We’re just transitioning into FEED now and hopefully by the end of this year, first part of next year, we’ll have those costs and be able to share with everyone exactly how much that might be. And we’re hopeful we’re determined that Etame 5H is not producing H2S.

If we determine that it is in the ideal world we can determine it’s not likely to show up in any of the other wells. So those are all reasons why we have hired the experts and we’re working diligently to better understand it and be able to forecast. Okay..

With that I believe we’ve finished our call today..

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