Good morning, ladies and gentlemen and welcome to the Gran Tierra Energy’s result conference call for the three months ended June 30, 2010. My name is Michelle and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the presentation, we will be conducting a question-and-answer session for security analysts and institutions. Instructions will be provided at that time for you to queue up for questions. (Operator Instructions) I would like to remind everyone that this conference call is being webcast and recorded today, Friday, August 5, 2010, at 10 o’clock a.m., Eastern Standard Time. Please be advised that in addition to historical information, certain comments made during this conference call, particularly those anticipating future financial performance, business prospects and overall operating strategies constitute forward-looking statements within the meaning of the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Such statements may be identified by words such as anticipate, belief, estimate, except, intent, predict and hope or similar expressions. Such statements which include estimated or forward-looking prediction and financial information or results are based on management's current expectations and are subject to a number of factors and uncertainties which could cause actual results to differ materially from those described in the forward-looking statements. Listeners are urged to carefully review and consider the various disclosures made by Gran Tierra Energy and its reports filed with the Securities and Exchange Commission, including those risks set forth in the Gran Tierra Energy's quarterly report on Form 10-Q filed with the SEC on August 6, 2010. And its annual report on Form 10-K for the year ended December 31, 2009, filed with the Securities and Exchange Commission, February 26, 2010. If one or more of these risks or uncertainties materialize or if the underlying assumptions prove incorrect, Gran Tierra Energy's actual results may vary materially from those expected or projected. Listeners are urged not to place undue reliance on forward-looking statements made in today's conference calls. Gran Tierra Energy assumes no obligation to update these forward-looking statements other than as may be required by applicable law or regulation. Today's conference call also includes non-GAAP measures; funds flow from operations, the press release, disseminated by Gran Tierra Energy last night includes a reconciliation of the non-GAAP item with the company's GAAP non-income as well as information about why management believes this measure is useful in evaluating the company's performance and is available on Gran Tierra Energy’s website at www.grantierra.com. All dollar amounts mentioned in today's conference are in U.S. dollars unless otherwise stated. Finally, this earnings call is the property of Gran Tierra Energy Incorporated. Any copying or rebroadcasting of this call is expressly forbidden without the written consent of Gran Tierra Energy. I will now turn the conference over to Dana Coffield, President and Chief Executive Officer of Gran Tierra Energy. Mr. Coffield, please go ahead.

Thank you, Michelle. Good morning and thank you for joining us, for the Gran Tierra Energy's second quarter 2010 results conference call. With me today is Martin Eden, our Chief Financial Officer and Shane O'Leary, our Chief Operating Officer. Last night, we disseminated a press release that included detailed financial information about the quarter. In addition, Gran Tierra Energy's 2010 report on Form 10-Q with three months ending June 30, 2010 has been filed on EDGAR and is available on our website at www.grantierra.com. I'm going to begin today by talking about some of the key developments for the quarter. Martin will then take a few minutes to discuss key aspects of this quarter's financial results. Shane will provide an operational overview and then I will return to provide an outlook followed by closing remarks. The second quarter of 2010 was highlighted by Gran Tierra Energy oil discovery as Moqueta-1 in the Chaza Block of the Putumayo Basin, subsequent drilling and logging at the Moqueta-2 delineation well, the second well in the Moqueta discovery, had additional positive results suggesting a net oil pay increased to 44 feet from a 26 feet in Caballos in Moqueta-1. Gran Tierra Energy production sales in the second quarter averaged 13,234 barrels of oil per day, a net after royalty, comprised of 12,515 barrels of oil per day in Columbia and 719 barrels of oil per day in Argentina. This is a 5% increase compared to same quarter of 2009 and a decrease from the first quarter of 2010 production of 14,908 barrels of oil per day, due to certain well pump failures and required recompletion of wells in both Argentina and Columbia and by the OTA pipeline in Columbia being offline for seven days during the second quarter. Funds flow from operations of $44.3…

Thanks Dana and good morning, everybody. Financially, the second quarter of 2010 was another strong quarter for Gran Tierra Energy. Revenue and interest income for the second quarter of 2010 was $84.1 million or 44% increase from the same period in 2009. This was due primarily to an increase of 5% in crude oil production and a 36% increase in crude oil prices. The average price received per barrel of oil increased by 36% to $69.25 per barrel at the three months ended June 30, 2010 from $50.79 per barrel from the same period in 2009. Operating expenses for the second quarter of 2010 amounted to $9.5 million, a 7% increase from the same period in 2009, due to expanded operations and increased production levels in Colombia. For the three months ended June 30, 2010, operating expenses on a barrel of oil equivalent basis were $7.83, a slight increase from $7.74 for the same period in 2009 General and administrative expenses of $9.6 million for the three months ended June 30, 2010, was 37% higher than the same period in 2009 due to increased cost reflected in company’s expanded operations. G&A expenses on barrel of oil equivalent basis increased 29% to $7.88 for the current quarter compared to $6.12 for the same quarter of 2009. Depletion, depreciation and accretion expense, DD&A for the current quarter decreased to $31.6 million, compared to $32.7 million for the same quarter in 2009. On a BOE basis, DD&A for the three months ended June 30, 2010 was $26 compared to $28.49 for the same period in 2009. This 9% decrease was primarily due to higher proved reserves in Colombia in 2010 used to calculate DD&A. Included in the second quarter 2010 results is a foreign exchange loss of $3.1 million, of which $1.3 million…

Thank you, Martin. This quarter, Gran Tierra Energy confirmed an oil discovery at its Moqueta-1 site and its continued worked on its capital program in Peru and Argentina. The Columbian program includes the drilling of seven exploration wells in Putumayo Basin this year with planned capital expenditures of $143 million. Initial testing on Moqueta-1, the first well of our 2010 exploration program showed 53 feet of hydrocarbon pay in Caballos formation and 26 feet of net oil pay in the Lower Caballos Formation. At the end of June, we mobilized the drilling rig used at Moqueta-1 to drill Moqueta-2 with drilling of the latter beginning in early July. Subsequent to the end of the quarter, positive initial wells delineations results were obtained at Moqueta-2 indicating total net oil pay of 44 feet and gross oil column height of 105 feet. We expect to complete the test program from Moqueta-2 by the end of the month. The Moqueta-3 delineation well, which will test the structure 300 feet down debt will be located approximately 1.5 kilometers Southwest at Moqueta-1 and is expected to spud in early December. The company is currently planning for the construction of a flow line from Moqueta to the Costayaco facilities approximately seven kilometers to the South and with long-term testing through the line is expected to be initiated in the first quarter of 2011. Having completed logging operations in production testing of Costayaco-11 in June, the company put the well under production in early July. Costayaco-11 is expected to be used as a Caballos and T-sand producer for a short period and subsequently as a water-injector to provide pressure maintenance in the T-Sandstone reservoir. Three additional wells have been added to the company’s exploration drilling program, including Popa-3 on the Rio Magdalena Block, Costayaco East-1 is scheduled…

Thank you, Shane. So for the full-year 2010, we continued to expect production average between 14,000 and 16,000 barrels oil per day net after royalty. And this includes approximately 13,000 and 15,000 barrels a day from Columbia and approximately 800 to 100,000 barrels a day of oil equivalent in Argentina. Our focus for the balance of the year is on executing our acceleration program and further delineation of the Moqueto discovery. This includes our third well in the Costayaco [ph] field in the fourth quarter and drilling up to six additional explorations well in Columbia with three drilling rigs active in the fourth quarter. In Argentina, the drilling of the Valle Morado sidetrack well in early third quarter with testing to follow in the fourth quarter provided an exciting opportunity to capitalize on stronger and natural gas prices in Argentina. With the extremely strong balance sheet, we continue to evaluate the number of new exploration and production opportunities that deploy this capital. But because of our large line acquisition and expensive near-term and drilling portfolio, we can forward new patents and select them as we pursue only those opportunities, where we feel we can truly create value by drilling. In completion, we have successfully built a solid foundation of land reserves, production in cash while hydrating our exploration portfolio which is now being tested to create additional value for all our stakeholders. We continue to explore exciting organic growth initiatives on our existing land for this year and next – complemented by the pursuit of new venture opportunities in our current countries of operation and in Brazil. Our proven approach to financial management coupled with our experience in finding and developing new oil reserves has served shareholder as well. We plan to continue this process into the future. I look forward to communicating our progress, as we proceed to the back half of 2010. So that concludes our prepared remarks for morning. We will now be pleased to answer any questions you may have. Michelle.

(Operator Instructions) Your first question comes from the line of Martin Molyneaux of FirstEnergy Capital Corporation. Please proceed. Martin Molyneaux – FirstEnergy Capital Corporation: Gentlemen, I take it as 7 kilometer trying from Moqueta. You’re looking at taking kind of six to eight months to get this in place I think, the challenges here, the environmental approval and then you’ve got the river crossing to undertake also.

That’s correct. The environment premise has to get certain light. There is a river crossing as we said. And then there is also a land acquisition to three pieces of what to be done at the process you’ve already started. And of course, we haven’t decided the design, the diameter of the (inaudible). Martin Molyneaux – FirstEnergy Capital Corporation: Right. You wait until production testing result come in for that.

Right. Martin Molyneaux – FirstEnergy Capital Corporation: Right. Okay. Thank you.

Welcome.

Your next question comes from Jamie Somerville of TD Securities. Please proceed. Jamie Somerville – TD Securities: Good morning. Couple of questions around the new budget. Just looking at the increase, I think it implies that you’re going to be spending around almost $90 million per quarter from Q3 and Q4. I don’t think you’ve been spending anything close to that today. Obviously, you’ve been staffing up and getting ready for this for long time. I’m just wondering with the timelines, how realistic is that uptick in our activity and particular with regards to some of the new locations that you’ve added to the program. Are those all permitted locations approved and rigs secured? Shane O’Leary: You’ll be willing to know that initial capital spending, not on staffing but it is on operation. There has been a significant delay in our operations particularly with Peru which is where significant slippage in budget has occurred. But the delay in permitting for the cyclic and drilling. Right now, often running, so we’re going to execute that program. We added well in Moqueta development wells and again in the rigs working in a production plate so that additional expenditure is going to happen, So I might – I guess the short answer to your question is yeah, there has been slippage in capital spending. Our capital spending has increased and it is – I'm trying to get it done this year. Jamie Somerville – TD Securities: And a couple of details. There was a well at Florida West that seems to have disappeared from the schedule. Shane O’Leary: Yeah. This has been dropped; just the other momentary prospect has taken this place. Jamie Somerville – TD Securities: Okay. And can you say why Costayaco East has popped up as near-term drill ready prospect, something changed in your utilization of that area?

What we’ve been doing is advancing our mapping or continued our mapping, not just that but a broadly worked prospects in our portfolio. And mapping reached a point where we’re comfortable drilling it. It is very perspective and we have a permit that we can drill a location front, so we can put it into the schedule and accommodate for the slippage to some of the other prospects. And just to comment, mainly to the east on the other side of wall (inaudible) both of the Costayaco field, so it’s a separate prospect, but it’s very close to Costayaco field. Jamie Somerville – TD Securities: Perfect. That helps. Thank you very much.

Your next question comes from the line of Rafi Khouri of Raymond James. Please proceed. Rafi Khouri – Raymond James: Yes. Thank you. Good morning, gentlemen. First of all, congrats on few things, Moqueto probably being the biggest one. Question on the Rio Mag Block, I’ve noticed that you’ve got back 40% operatorship and there are another sort of 4%, you got the proprietary drilling. You mentioning oil prospect, I always thought that it was more gassy, especially in the months of that formation. So just curious as to what the – though on the oil in the sphere and then may be more general, was that sort of the rationale in getting the Block back versus having opted to sell it sort of late last year.

That’s a prospect we’re drilling is not an old prospect, Popa-1 and Popa-2 as you know found out, this is actually such a prospect at a shallow level, unfortunately it was already named with Popa-3 well, because of shower that’s why I was expecting to find oil, of course, the gas, we’re also looking for oil. I can’t really comment on details that how I likely got the interest back rather than to say that we had got the interest back and the prospect for doing this one is that was mapped and defined by the Gran Tierra team. Rafi Khouri – Raymond James: Perfect. That’s actually – okay. You can’t comment, but fair to say that you guys saying the block are definitely worth having, or else you probably wanted to take it back.

Yeah. Rafi Khouri – Raymond James: Perfect. Thank you very much.

Your next question comes from the line of Cristina Lopez of Macquarie. Please proceed. Cristina Lopez – Macquarie: Hi guys. Just a couple of quick questions, one is with respect to the capacity from the Guayuyaco line to Morado [ph] where you have sufficient capacity with new discoveries on the Chaza Block or are you looking at now on expansion as well from (inaudible) that was the big bottleneck. Shane O’Leary: If we make modest discovery or small discovery, what we probably knew is that expand our trucking capacity. If we have to make a large discovery then we would twin existing pipeline. Those two segments, we may twin one or both depending on the scale of a new discovery. Any breakeven in say field side that would trigger that is kind of grey area that twins on productivity and floor rate and such. Just, despite to say that was a small discovery, we would just expand trucking capacity, large discovery; we would have to twin the pipeline. Cristina Lopez – Macquarie: And I may have missed the answer to this one, but it seems like there is a Sarbanes-Oxley, the Argentina Caballos, I’m just curious is that just cost over runs on the workover on the Valle Morado Block or if it is related to something different?

This is higher. This is costly sidetrack. It is higher than we originally budgeted as one item and then we’re doing additional facility upgrading of the gas processing plant. And those numbers are higher than we originally budgeted. Cristina Lopez – Macquarie: :

No. We’ll have some of the seismic interpreted, but it won’t influence the location of the wells. That’s being redefined with the environmental furnace we have. Cristina Lopez – Macquarie: Okay. And I believe that’s it from me. Thank you so much.

Great. Thanks, Cristina.

Your next question comes from the line of Neal Dingmann of Wunderlich Securities. Please proceed. Neal Dingmann – Wunderlich Securities: Good morning, guys. Let say, first question, I was wondering on – you mentioned in the press release about likely drilling a significant well in Argentina, I was just wondering your thoughts about the pricing environment there. If you are becoming more encouraging, after this as well, will you continue to become more active in Argentina going forward? Shane O’Leary: Yeah. We are actually very encouraged by gas prices in Argentina. You are also seeing some major companies come in just to pursue gas opportunities now. But when we look at the product, the potential productivity of this well and getting to see somewhere between $4 and $5 in MMbtu, this thing can be a real cash scale for Gran Tierra, potentially generating $30 million a year for a long period of time. So it’s definitely worth pursuing. Neal Dingmann – Wunderlich Securities: Got it. And then I was wondering, as far as in Brazil, you mentioned about opportunities there but I think in the press release, you didn’t mentioned, but potentially drilling wells, I was wondering sort of the near term any plans or is it more just on size, looking that sort of thing or is there some wells or there is some sort of site that you are starting to identify. Shane O’Leary: We are looking at half a dozen opportunities at any one-time in Brazil. We are continuing to evaluate those. Well, at this point in time, we do not have any acreage in Brazil. So we are evaluating the number of opportunities and hope to have a position here in Brazil, sooner than later preferably. Neal Dingmann – Wunderlich Securities: Okay. And then it appears, after the results that you are seeing so far in the Moqueta-1 and 2 that – now, you are drilling six wells. I mean, again, how fluid, Dana, is that sort of CapEx so that – those plans based on sort of its results, if those wells cumbered, you will drill six regardless or could that change this year or even going to next year but depended on results.

We are going to proceed to drilling of all the wells that we’ve talked about. That uncertainty would be on timing, interpreting what experiences here, as we have others, because of the Moqueta success, we kept the rig there so that delayed through the drilling. We actually added three wells to the program. We’re constantly high grading in the portfolio. So well, we are constant, reflect those – additional wells been added and perhaps one or two been drop. So currently, (inaudible) drill, essentially, if we don’t program, we laid out, plus these additional three wells and it’s just going to take a little bit more time to do drilling. There are no wells that we had budgeted at beginning of the year. Neal Dingmann – Wunderlich Securities: So it sounds like lot of potential there. Last question maybe for, Martin, just – around that FX loss this quarter, I mean is there anything sort of going forward to add something where you can lock in that to maybe mitigate some of this FX or is there just anything to do around that. I guess one part is that you’re trying to model that.

We thought about hedging, but especially it’s an accounting loss actually. When you go into the expensive, taking how to hedge, which has real costs just to try and hedge an accounting loss. So it’s basically, whatever the exchanges rates do, it will impact our net income going forward and we probably will predict what this is going to be. Neal Dingmann – Wunderlich Securities: Absolute. Okay. Fair enough. Thanks, guys.

Thanks, Neal.

Your next question comes from the line of Alexander Klein of Dundee Securities. Please proceed. Alexander Klein – Dundee Securities: Good morning, gentlemen. Just a few questions here. Just wondered if you could give us some color on the production that was curtailed here in Q2, as a result of the pump failures and workovers, where did this occur and how much production was actually curtailed? And then as a follow up, is that production back online now and if not, why not and when will it be? Shane O’Leary: Okay. I’ll address that. In Argentina, we are down about 200 barrels a day, that’s just due to accessing service rates and weather conditions that have been bad in the areas we are producing, so access has been an issue. In Columbia, C-1 went down and we had to work over and recomplete that as well and we lost. That was quite a significant well, lost about 1000 barrels a day there. And J-1 has been declining due to scaling problems and so we’ve had to work over that rig. Some of these workovers have led us to the conclusion that we need to be able to access more than one service rates, which we – the only one, we currently have been working in our area. And that’s proving to be an inadequate. And then, of course, the OTA was down for seven days and although that was for a very long period, when you start averaging sub sounded, it hurts. So, okay, backup and J-1 is being worked over, we decide to frac at that well at the same time, so it’s taking a little bit longer to get back online and C-1 has been re-completed. And so we’re fully expecting to – on a yearly average basis, produce within our guidance from 14 to 16,000 barrels today corporately. Alexander Klein – Dundee Securities: Okay. Thank you. And just follow-up on the exploration side, with regard to Pacayaco and Costayaco East-1, from a geological perspective these similar kinds of, structures to Moqueta and Costayaco. Are you targeting the Caballos and Villeta reservoirs? Can you give us a little color on that please?

All the prospects in the Putumayo portfolio are targeting these reservoirs. The prospects where the structures are all similar and trying to reverse those, the Costyaco East is actually a different type of truck. It’s a footwall truck, relying on the plateau [ph]. It doesn’t, after all consistent, cut back at same reservoir, same oil wells… Alexander Klein – Dundee Securities: So given the success at Costyaco and preliminary success at Moqueta, do you see the probability of success of those two wells being higher than they’d normally it would be or were they completely independent?

They are independent. Alexander Klein – Dundee Securities: So what are we looking at, 20% chance of success?

Individual cross explorations, 20% to 40% chance of success. The average program is probably around 13. Alexander Klein – Dundee Securities: Okay.

30%. Alexander Klein – Dundee Securities: Great. That’s it from me. Thanks.

Fine. Thank you.

Your next question is a follow up from Rafi Khouri of Raymond James. Please proceed. Rafi Khouri – Raymond James: Yes. Thank you. Just wanted to, sort of, circle back a bit on the exploration program, Dana. The six remaining wells could be drilled now and earlier on, we had 23 million barrels risks for seven wells in Columbia. Of those six, we’ve got a few new ones and few ones that got pushback to 11 of the six that are left to drill. Are we still looking at $23 million on the risk – sorry, a risk – if we do include, if we consider Moqueta has not yet been drilled or theoretically, keep the number in there I guess as a risk number, are we still at 23 or is it higher or lower?

Well, for the program it would be the same and so the wells have been deferred into first half or first quarter, perhaps next year plus these three new ones, the risk number will be higher. We’ve got three more prospects. Resource potential lease is consistent with the other, so we add approximately 9 million barrels of net risk resource potential to the program. Rafi Khouri – Raymond James: And if we stripped off Moqueta from that total, what do we get?

We are still trying to figure our outlook. Moqueta has a bit – take it out but the net risk resource potential, it’s probably around three or so. Rafi Khouri – Raymond James: Okay. Perfect. Thank you.

You have a follow up from Jamie Somerville of TD Securities. Please proceed. Jamie Somerville – TD Securities: Hi. Thanks. Just following up on Rafi’s earlier questions. On these, some of your earlier announced asset disposals – if I recollect correctly, the Rio Magdalena disposal went hand-in-hand with the Mecaya disposal. Just wondering that disposal was still going ahead, is that correct?

No. It’s not. Jamie Somerville – TD Securities: So you will be returning the interest in the Mecaya Block. And I guess related to that there were letters of intent for multiple blocks including the Garibay Block. I’m just wondering if we should consider those as cancelled.

Those are not yet sold. The Garibay and also the un-doubling on the blocks in the far north had good blocks. Those transactions are not yet closed. Jamie Somerville – TD Securities: If the letters of intent are still in place?

Yeah. Jamie Somerville – TD Securities: And sorry, just lastly on this – obviously you have taken an additional 4% in Rio Magdalena, which assumed that that was for no consideration?

Correct. Okay. Jamie Somerville – TD Securities: Thank you very much.

Yeah.

Your next question comes from the line of George Toriola of UBS Canada. Please proceed. George Toriola – UBS Canada: Thanks. Good morning, guys. Just a couple of questions. The first one is on the production profile, particularly, out of Costayaco. What I’m wondering here is what type of exploitation activity do you have of that support – essentially holding production flat here, maybe you can just provide some color into what you’ll be doing, assuming between the Caballos and the T-sands. That’s sort of thing.

Well, the field is relatively young. So it’s in its plateau phase and based on reservoir modeling, we are projecting sort of a two to three year plateau. The types of things, we will be doing more off is water flooding. Going forward, we are starting now to drill water injector wells and we are going to be injecting water – starting in September in C-5 and then later on into C-11 as part of our reservoir modeling. We need to inject water into the T-sand. We will be adding development wells over time. We think we’ve got enough wellbores into the structure at this point in time to maintain plateau. So going forward the production strategy is to increased water handling, inject water, drill development wells as needed and hold plateau as long as possible. George Toriola – UBS Canada: Okay. Thanks. And secondly on the – I’m just wondering on the Rio Magdalena Block, Popa-3 well, just wondering why that – why are you drilling that now as against everything else is just – is this licensing, why does it sort of come up at the top of your drilling priority right now?

It’s a good prospect and we wanted to drill it before license expiry, which is this year. They wanted to drill before it was (inaudible). George Toriola – UBS Canada: Okay. Thanks a lot.

Welcome.

Your next question comes from the line of Martin Molyneaux of FirstEnergy Capital Corporation. Please proceed. Martin Molyneaux – FirstEnergy Capital Corporation: Gentlemen, we have now seeing specific (inaudible) chemical industries announcement, that (inaudible) is seeking a Columbian listing. Have you wrapped your mines around this and any thoughts on that in the future? Shane O’Leary: We are considering it, but we have not made any decision. There’s strongly a lot of interest in Columbia for Columbian names, but we have not persuaded at this time. Martin Molyneaux – FirstEnergy Capital Corporation: Okay. Thank you.

Your next question comes from the line of David Dudlyke of Stifel Nicolaus. Please proceed. David Dudlyke – Stifel Nicolaus: Yes. Good morning, everyone. Referring to the shortfall of Q2 over Q1 with respect to production, I just want to explore a couple of things, how much did the pipeline shutdown contribute to the shortfall? I mean, obviously, seven days storage on a gross basis could amount to something like a 125,000 barrels. But how much storage was in fact available to you, so that you could basically store your production and then subsequently evacuated?

There wasn’t that much storage. I think, we were able to produce for about two days and then we had to shut-in. David Dudlyke – Stifel Nicolaus: Okay. The obvious follow-up would be, do you guys plan to add any further this spoke storage to cater for such events. I mean, those seven-day shut-in, I know, that the intervention on this pipeline have been reduced in frequency of late, but nevertheless, shut-in are shut-in, would you plan to add any storage?

No. I don’t think so, I think, we’re comfortable with the level of storage we have and as you mentioned, this incident seem to be coming fewer in frequency than more so also. David Dudlyke – Stifel Nicolaus: Okay. And you did speak about the – the question regarding the nature of the recompletion and work hours, and you spoke to that. But, I guess, my question would be, given that, well, of this past, are any of these wells recompletion associated with depletion of the Villeta sands. Are you opening up any fresh sands at Costayaco and did that form any part of the recompletions in Q2?

No. David Dudlyke – Stifel Nicolaus: Or they were all caused by problems with wells?

Yeah. Expect for, we did open up with C-11, we opened up a new area of the field but not with the recompletion, no. David Dudlyke – Stifel Nicolaus: Okay. I think, well, in fact, that forms a question. What is – can you speak to what production you’re getting from C-11, because is that coproduction with both sands?

No. It’s only producing from one sand, its producing about 1000 barrels a day and it’s only going to be briefly because we did drill that’s to be an injector. And but we didn’t, if you start injecting water right away, you’re going to be stranding some reserves. So, we’re trying to deplete a little bit of the area, before we start injecting water to get the benefit of the oil in that area. So it will just be a temporary thing. David Dudlyke – Stifel Nicolaus: Okay. And temporary, meaning, what a matter of months?

Yes. Say two months, something like that. David Dudlyke – Stifel Nicolaus: Okay. And there was question that, I think, Christina asked regarding pipeline capacity. You don’t stood around what the hurdle rate would be for a pipeline versus trucking, perhaps in terms of speaking to size of discovery, perhaps if we just deal into the off take well productivity, what level of production would be required from a new discovery or discover is for you to basically invest in additional pipeline capacity?

10,000 barrels a day. David Dudlyke – Stifel Nicolaus: Okay.

Below 10,000 barrels a day, we would drill 10,000 barrels a day, we expand trucking capacity more than that, we’d have to think about pipeline economic. David Dudlyke – Stifel Nicolaus: I mean, perhaps, you can remind me, how much that capacity does actually exists within the pipeline network downstream at Costayaco, first of fall, within your own time pipeline, but second within the network there after than Orito?

The north-south segment to our self point has between 5 and 10,000 barrels a day, they are classic. David Dudlyke – Stifel Nicolaus: Yeah.

From Santana West to Orito they were zero. David Dudlyke – Stifel Nicolaus: Yeah. That was always the checkpoint.

From Orito Peidemonte there is a big around 45,000. David Dudlyke – Stifel Nicolaus: Yeah. Okay. If I may, a question of detail. On DD&A, I know that the units DD&A felt significantly from 1Q to 2Q and I know, was on a gross barrel basis from some 2,250 to 1,850 per barrel. Now, while the reserve base and you talk about this in the press release, while the reserve base would be different from year-on-year comparison, I would have thought that the first quarter, second quarter reserve base would be have been identical, so perhaps, can you speak to the decline in the units depreciation second quarter to first quarter, essentially what should be the – what would your guidance here will be?

June – first quarter we had to write-down on our Argentina assets. David Dudlyke – Stifel Nicolaus: Yeah.

… so $8.7 million that affected the rate in the first quarter. David Dudlyke – Stifel Nicolaus: Okay.

The second quarter rate would be what you anticipate going forward. David Dudlyke – Stifel Nicolaus: Fair enough. And if I may, one last question, you spoke earlier to the delay to your drilling program in Columbia, and indeed I have no problem with delays to exploration with appraisal of success, but I do note the permitting raises its ugly ahead, yet again, and I see that reference in a number of the wells, if I just pick one, Rio Blanco just as an example. I mean that was being spoken about I know within your presentations mid last year, probably early last year. I just want to get a better feel as to what take so long with regard to the permitting. Because I was under the impression there was a fairly well understood and transparent process within the regulatory authority for such permitting?

The environmental permitting process is very – it's very well defined in Columbia… David Dudlyke – Stifel Nicolaus: Yeah.

… this month, it can become complicated or extended basically goes up and then a year along attention if that was own community to identify. And thus, they can have expensive delays and then it was also here in a coastal area, there’s additional permits required, forestry permits for cutting the trees for locations. So these are additional factors that can change permitting schedule or timing for different work. David Dudlyke – Stifel Nicolaus: Yeah. I mean, I guess, if I was to play devil’s advocate, my bold question to you would be could or should any of these various institutes have been anticipated given that unless I’m mistaken a good number of these prospects have been in your inventory and planned in your drilling plan for some time. And essentially anticipation of such things you may have been able to sort of albeit the delays that we’re now seeing.

Well, there’s two things that has which could have productivity because we’re now seeing requirements to consult within this communities outside their areas. So if you’re looking at operations near, average on community area being here, now requires concentration. David Dudlyke – Stifel Nicolaus: Okay.

And the other is of course, sea waters change and that is one of our blocks that was the case where we firstly portion what is where on the maps, what the maps there were and thought we’re not correct. David Dudlyke – Stifel Nicolaus: Okay. Fair enough. Thank you for all your answers to my question. Thank you very much.

Thanks, David.

Your next question is from the line of Frederick Cozak of Cannacord. Please proceed. Frederick Cozak – Cannacord: Good morning guys. Thanks very much. Most of my questions have been answered. I just want to explore though, something that may or may not being impact to you guys. Petrominerales put up their press release month or so ago that they were having an issue with the ANH on their – on the interpretation of the contract, exploitation areas versus the block for the high price royalty, given that you’ve got Costayaco, now discovery on Moqueta and are still doing exploration on the Chaza block have you had any conversation with the ANH on this topic and what is your view of what you have in terms of contract and the potential for dispute with ANH for high price royalty?

No, I don’t see any dispute with ANH. Our contract is very clear. The high price royalty is on exploitation area, by exploitation area; those are almost at a cost like completely outside the exploitation areas, Costayaco, we don’t see that as an issue. Frederick Cozak – Cannacord: Have you actually have the conversation with the ANH about that?

Personally, I haven’t. No, I know it really help write the contract our company manager. Frederick Cozak – Cannacord: Okay. That was – do you have an update presentation that you’re going to post that shows Costayaco East or Pacayaco location on your Chaza Blocks?

I was afraid you’ll ask that. So I guess, I have to yes, we will, it’s not really yes but there will be. Frederick Cozak – Cannacord: Okay. Thanks very much.

Okay. Thank you, Fred.

Your next question is another follow-up from Rafi Khouri of Raymond James. Please proceed. Rafi Khouri – Raymond James: Thank you. So let’s follow up some of the production question that George was asking. Most specifically, can you tell us if you saw anything positive pressure wise, once you brought the wells that were shut in back on, Costayaco-1 being one example, the second sort of link to that question is, senior term what two to three years plateau production – if I can very simple if we take the two pee reserves booked at end of ’09 divide them by current production. I can’t get to two or three years. So are you seeing something that gives you confidence, you’re going to see some of the possible bumped up or are they’re going to produce some of the possible?

Well, first of all, I don’t write it as a model. It’s not the same as GLJ. We make our decision on what – on our reservoir modeling. And we saw, I mean we see that there’s more outsider reserve then GLJ there but, of course all we’re allow to do is to report GLJ reserve. Well, if you’re using the GLJ reserve from last year, it’s not surprising you’re coming to that conclusion. It’s been on plateau year already. Rafi Khouri – Raymond James: No, exactly and so I guess to sort of may be rephrase my question, do you think there’s anything data wise especially that you did have well shut in, so we’re going to see some nice, I am assuming we might have seen some less pressure built as well. If there were the case, do you have any data that you think as GLJ revises their reserve at the end of 2010 for Costayaco, they should be giving sort of an increase in 2p reserves obviously exploiting production that you will have this year?

Well, I mean the Caballos reservoir has a very active water rise. So it’s been very low depletion of pressure in the Caballos. The T-Sand it does, it has some water dry by not as active and that has been the target of water injections. So we didn’t really see anything that surprised us in shutting in the wells. I mean, we don’t see much pressure depletion in the Caballos, for example. But I don’t – we’re not expecting, today I can’t say that will have reserve addition from GLJ at the end of the year, based on anything that’s going in the field. Rafi Khouri – Raymond James: Okay. That’s perfect. Thanks.

Gentlemen, there are no further question, please continue.