Good morning, ladies and gentlemen, and welcome to Gran Tierra Energy's results conference call for the 3 months ended March 31, 2011. My name is Sev, and I'll be your coordinator for today. [Operator Instructions] I would like to remind everyone that this conference call is being webcast and recorded today, Tuesday, May 10, 2011, at 10:00 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 provisions of the Private Securities Litigation Reform Act of 1995. Such statements may be identified by words such as anticipate, believe, estimate, expect, intend, predict and hope or similar expressions. Such statements, which include estimated or forward-looking production 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 Gran Tierra Energy's quarterly report on Form 10-Q filed with the SEC on May 10, 2011, and in its annual report on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange Commission, February 25, 2011. If one or more of these risk 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 call. 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 the non-GAAP measure funds flow from operations. The press release disseminated by Gran Tierra Energy last night includes a reconciliation of this non-GAAP item with the company’s GAAP net income or loss, as well as information about why management believes the measure is useful in evaluating the company’s performance, and is available on Gran Tierra Energy’s website, www.grantierra.com. All dollar amounts mentioned in today’s conference call are in U.S. dollars unless otherwise stated. Finally, this earnings call is the property of Gran Tierra Energy, Inc. 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. Good morning, and thank you for joining us for Gran Tierra Energy's First Quarter 2011 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 2011 report on Form 10-Q for the 3 months ending March 31, 2011, has been filed on EDGAR and SEDAR and will be 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 outlook, and I will return to provide closing remarks. The highlight of the quarter was the announcement and subsequent closing of the acquisition of all of the issues and outstanding shares and warrants of Petrolifera Petroleum, which closed on March 18, 2011. This acquisition is significant for Gran Tierra Energy as it adds undeveloped gas reserve potential in Colombia, oil exploration opportunities in Colombia and Peru and additional oil production and reserve development opportunity in a rising oil price environment in Argentina. The second significant highlight in the quarter was the continued reserve growth of the Moqueta oil field. Since the beginning of the year, we had drilled and evaluated 2 additional delineation wells, both encountering more oil than has been previously encountered. We still have not found the limits of this growing asset. No oil-water contract has been found in any of the reservoirs and any of the wells drilled today. We are now planning 2 additional delineation wells to further evaluate the extent of the oil column in the field. The next well…

Thanks, Dana, and good morning, everybody. Financially, the first quarter of 2011 was a very strong quarter for Gran Tierra Energy. Revenue and interest income for the first quarter 2011 was $122.5 million, a 32% increase from 2010, largely due to an increase of 36% in realized crude oil prices. The average price received per barrel of oil grew by 36% to $94.31 per barrel for the 3 months ended March 31, 2011 from $69.20 per barrel from the same period in 2010. Operating expenses for the first quarter of 2011 amounted to $16.4 million, a 61% increase from the same period in 2010, due mainly to high workover costs, high fuel and power costs, water injection costs and higher trucking costs due to Tumaco Port maintenance in Colombia. For the 3 months ended March 31, 2011, operating expenses on a per barrel of oil equivalent basis were $12.52, an increase of 65% from $7.57 in the same period of 2010, again, due to increased operating expense coupled with a marginal decline in production from the same period last year. General and administrative expenses of $13.6 million for the 3 months ended March 31, 2011, were 90% higher than the $7.2 million for the same period in 2010, due to increased employee-related costs reflecting the expanded operations and the costs related to the acquisition of Petrolifera. Consequently, G&A expenses on a per barrel of oil equivalent basis increased 95% to $10.42 for the current quarter compared to $5.34 for the first quarter of 2010. Depletion, depreciation and accretion expense, or DD&A, for the current quarter increased to $63.4 million compared to $40.3 million for the same quarter in 2010, due primarily to a $31.9 million ceiling test impairment in our Peru cost center. On a per BOE basis, DD&A for…

Thank you, Shane. Gran Tierra's work program is intended to create both growth and value from our existing assets while retaining financial flexibility so we can be positioned to undertake new developments on our assets and to pursue additional acquisition opportunities where we see additional value creation opportunities. Our 2011 capital spending program of $357 million for exploration and development activities in Colombia, Peru, Argentina and Brazil includes $190 million for drilling, $79 million for infrastructure, $87 million for seismic acquisition and $1 million for other activities. Of the $190 million related to drilling, approximately $87 million is for exploration and the balance is for delineation and development drilling, a healthy split between developing existing reserves and exploring for new reserves. With this capital program and as a result of the Petrolifera acquisition, Gran Tierra has increased production guidance for 2011 since the acquisition of Petrolifera to between 17,500 and 19,000 barrels of oil equivalent per day net after royalty, with 96% of this being light oil. In Colombia, 3 additional blocks were added to Gran Tierra's portfolio following the Petrolifera acquisition: Sierra Nevada, Magdalena and Turpial. Both exploration and delineation drilling is planned for this year. In addition, we added 2 exploration blocks in Peru, Blocks 133 and 107, which will commence next year. Finally, work has already begun on our new fields in Argentina, stemming the production decline and now preparing to grow production. In the first 4 months of 2011, Gran Tierra Energy has successfully grown land, reserves and production while hydrating our exploration portfolio to create additional value for all our stakeholders. Our prudent approach to financial management coupled with our experience in finding and developing new oil fields has served shareholders well so far. And we are on track to continue this successful growth into the future. I look forward to communicating our progress as we proceed to the coming year. Now that concludes our prepared remarks for the morning. We would now be pleased to answer any questions you might have. Sev?

[Operator Instructions] And your first question will come from the line of Nathan Piper with RBC Capital.

A couple of questions if I may. Firstly, on Peru, with the Kanatari well results kind of putting you off drilling any more wells on Block 122 at the present moment, how should we take that? I mean, should we put a whole line through 128 and 122 or do you think that there will be the potential to come back to those blocks in the future? And second question, on Moqueta, if we were to take a step back here and if you were to sell to spill the current prospect side, the current structure that you see, what kind of -- what is the potential of the Moqueta structure as you understand it now? And then lastly, can you give us some guidance on your Argentina realizations? Are oil prices and gas slightly improving there?

Yes, let's see. I guess, we'll go to Peru first. The current locations we have permitted, we have 4 additional locations permitted, do not have any trapping potential given the low results we have with the Kanatari well. So we're continuing to evaluate additional potentials for the future, but the reality is our portfolio has dramatically changed in Peru. Historically Blocks 122 and 128 were the priority. They no longer are. They're a part of a much larger and robust portfolio. So things like Block 95, where there's already the oil field are much higher priority for us. So it's not a top priority. It's now just part of a mix of other opportunities we have in Peru. Your second question?

On Moqueta, Dana. I know I'm twisting your arm a little bit here, but how big is the Chaza Block [ph] do you think? Can you just give us some sense of scale?

Well, I have to qualify we're on the same because we actually don't have a map of the entire structure. It's an anticline that's overridden by another fault, we have base in it over part of the structure and we have no seismic images below basement. So we actually don't even today know what the shape of the structure is. Hence, we're doing this in 3d seismic I'd say it's unlikely it's as big as Costayaco and -- but it's likely larger than the reserves that have been booked to date. That's kind of a rough answer, but it's the best I can do. And then Argentina realized prices, we're currently realizing $58 in the Neuquen Basin. And we are continuing to see oil prices rising as we speak in Argentina. Martin, do you want to say a few words?

The realized price for Argentina in the quarter was about $54.50, and typically the prices have been going up $0.50 every month. We don't know for sure if that will continue in the future. But we certainly are getting much better prices than last year. As Shane mentioned, it's higher in the south with the Petrolifera properties. The price in the south is higher than in the north, $58 versus $56.

Your next question will come from the line of Martin Molyneaux from FirstEnergy Capital Corp.

Gentlemen, given that Moqueta is growing in size with the recent joint results, we've got a 6-inch line installed or about to become operational, what's the capacity of that line? And given the drilling results, are we going to have to go through a second six inch line to get to more reasonable production profile?

Right now, we think we can get 20,000 barrels a day more or less through the line. So we think it's going to be adequate for a reasonable outcome. If we need to tweak it [ph] or expand capacity, it's pretty straightforward. It took, start to finish, I think it's 6 or 8 months to build this initial flow-line. I think we've got most outcomes covered with this line.

And in terms of some kind of production ramp from the 500 barrels a day that you disclosed in the release, what's your current thinking given the well results so far?

Well, it's really tough to answer because the oil is saturated with gas. So we'd either re-inject gas, maintain reservoir pressure so that gases will come out of solution from the increasing wellbores, leaving oil behind. So we really need more substantial reservoir performance data before we can provide any realistic guidance on the productivity for each well. It's a very different reservoir properties than we have in all of our oil-producing fields.

Does that mean that you'll produce with the line operational? That means you'll produce the wells kind of in a sequence to test them out?

Initially, yes. For this year, we'll actually flow individual reservoirs within each well. And then, commingle perhaps -- yes, we'll commingle reservoirs in individual wells. So this -- production this year is going to be a long-term testing program for oil-producing individual wells and individual reservoirs within those wells. And then there will be some commingling and perhaps some commingling of wells also. All that specific planning hasn't been done yet until we start getting initial data.

Your next question will come from the line of George Toriola with UBS.

My first question sort of follows up on what Martin was talking about. 500 barrels a day, how have you -- is that just a guesstimate today or how have you arrived at that relative to your well test results?

Well, some days, it will be zero and some days, it will be 1,000 barrels a day. So it's just an average a conservative average of what we think will be the production for the coming year. And we'll be doing pressure buildup tests in wells or individual reservoirs so there will be no production. And at other times, we'll be flowing wells at higher rates to see how the reservoirs perform. It's just a conservative estimate of what we expect this year averaging it out.

Okay, thanks. And maybe to ask a bit differently as well. Would you suggest that the test rates that you've had on the wells so far, is that representative of productive capacity or you can't tell at this moment?

No. No, certainly not productive capacity...

Production potential, I should say, not productive capacity.

I'll say, in our nearby existing creasing field will typically crease around 2,000 barrels a day, seeing the range from 1,000 to 4,000 barrels per day. Our concern is -- and we have the same reservoir, the same permeability and similar oil with the exception that the oil has a higher gas content. We don't want to be drawing on the reservoir at those levels until we have adequate pressure support to keep the gas in solution. So the answer is the reservoirs would expect to be able to produce somewhere between 1,000 and 4,000 barrels a day after we have compression support system in place in the field.

Okay. So you would -- the plan is that you would re-inject all of that gas at Moqueta?

Correct. That's the current thinking, yes.

Okay, thanks. And last question here is around the ANH, the disagreement you have with the ANH, can you talk a little bit about how -- it's a little bit surprising that the Chaza Block, I'm sorry, the Moqueta structure that is not yet in production, all of this discussion is arising. Can you talk a little bit about the discussions you've had and how you expect to resolve this?

Well, we actually haven't had any discussions yet. We were notified that they just recently that they were claiming payments for the test crew for Moqueta at the same rate as the payments for Costayaco. So we've sent them a letter asking them for clarification on why they think that is the case. And that's full stop all the conversation and communication that's happened to date. So it's very early days. We don't understand their position. We do understand our position. And we'll just work through it with them and sort it out.

Okay. And your position is that -- maybe you should kind of just talk about your position. How do you interpret the 5 million barrels per structure, based on geology, how do you interpret it?

Well, we don't actually interpret it. It's stated clearly in the contract with ANH that applies to each development area. You draw a polygon around your development. In which case, we have an area defined for the Costayaco field. Within that area, within that polygon, that's been defined for the development. Once production from that polygon exceeds 5 million barrels, then you pay an additional royalty. The polygon could include 2, 3 or 4 fields or just one. But in our case, in this case, it's just the Costayaco field area. The Moqueta lies outside that area.

And there's no -- can the polygon be re-drawn? Or once it's set, it's set?

Once it's set, it's set. I mean it's defined.

Your next question will come from the line of Jamie Somerville with TD Securities.

Just looking at your budget for Brazil and compared to previous you have it at $60 million currently and set to get 4 wells drilled in 2011. I think you previously had $55 million in 6 wells getting drilled. Are you concerned about a slight delay in some of those wells getting drilled? I just want to check that there isn't any increase in costs going on here that maybe you can explain?

No. There's been some delays. We have waited almost 6 months to get approval from the ANP for 3 of the 4 blocks, and we're waiting for the final approval on Block 155. We don't have that yet. We're coming up on 8 months. And that's impacted the drilling program. It's very difficult for us to get after it except if we work through the existing operator to get work done. So there's no question that the ANP approvals have slowed us down a little bit. There's a little bit of uncertainty as to what rig we're going to use to drill the horizontal leg for the 3 wells we've got planned, the horizontal wells. And we may be able to do it with some rigs that drills vertical pilot hole or we may not be able to. We're currently talking to various rig contractors, and we'll know soon what the situation there is. But the best estimate we have today is that we'll get the 4 wells drilled and 2 wells will spill over into 2012.

Yes, that's fine. Thanks. I think my other question is for Martin. You mentioned the accounts receivables being due to Ecopetrol-related issues. But it looks like your accounts receivables has increased by almost $100 million, which is a pretty significant amount. Did you say, is that all due to Ecopetrol and do you expect all of that to be adjusted for back to a normal level in coming quarters?

No. It is mostly due to Ecopetrol. I mean at year end, we have 19 days receivables, quickly run 60 days receivables. Also, the prices have increased in Q1 also. So we kind of would expect that kind of level of accounts receivable to continue.

You don't expect to go back to a lower level of 19 to 20 days?

Well, it will go back at year end. But it's only at year-end that, that happens. It's just that Ecopetrol at year end sort of settles it's receivables. So we typically have sort of 19 to 20 days receivables at year end. But the balance of the year, it's always 60 days. So the year-end position sort of corrects itself by the end of March, and that will continue throughout the year until December when again, we'll have 19 to 20 days receivables.

Your next question will come from the line of Hubert van der Heijden with Tudor, Pickering, Holt.

Just looking at your price realizations in Colombia, they are above WTI. Have you been able to shift some of your contracts to Brent-link pricing? And how should we think about pricing in second quarter and onwards?

We haven't linked it to Brent, but there is a clause in our contract with Ecopetrol where they are realizing higher prices. There's a formula that allows us to recoup some of that higher pricing.

Ecopetrol was able to sell us a premium to WTI in February or March and also in April. We don't know for sure what's going to go forward, but they're realizing better than WTI prices from their buyers and we share in that premium.

Okay, that's helpful. And just on the Block 95 in Peru. So the site prep begins in Q3, but the well won't spud until 2Q '12. I thought initially it was supposed to be for the fourth quarter. What is kind of leading to the delay there?

It's a very difficult area and the service location. It's on the -- well, near the Amazon River, so it's flooded for a good part of the year. So it's going to take a lot of work to build a drilling platform above the flood line. So it's going to start at -- construction will start right at the end of the third quarter and then drilling will begin in the second quarter. And then there's -- we're giving consideration for using one rig for that and another block so there will be potentially some timing adjustments to accommodate drilling campaigns on 2 different blocks.

So there's no issue with the availability of the rig and services there?

We're evaluating that right now. So there's a limited number of rigs. But right now it looks like we have 2 rigs for the drilling campaign.

We don't have all the permits we need. We need a deforestation permit to really start work, and we do not have that in hand. And that's one of the critical timeline issues that is still outstanding.

Your next question will come from the line of Neal Dingmann with SunTrust.

Dana, with -- around the Brillante, the gas well, is the thought just to drill one well this year and then kind of after the seismic shots, see what kind of prospect there or kind of walk me through, I guess, kind of what the plans are for the next year there?

There's a discovery well in the field. And then there's a lease grade of 2D seismic data. What we want to do this year is drill a delineation well to try to prove up the large 3P reserve number that we have in the field and essentially try to move as much of that into the proved category if we can, which will then allow us to undertake margin initiatives for the gas once we've proved up a reserve base. Now we're shooting the 3D seismic in parallel so that we can further define the details of the reservoir distribution that we can then use for subsequent development drilling sometime in the location of the development wells. So the objective this year is to prove up reserves with the delineation well. Next year, initiate gas marketing and pipeline construction, and then drill additional wells as required to develop the field.

So you can add some production flowing, would it be next year or would that be in 2013 then?

Well, actually, we have a nominal amount of production in the beginning -- in second quarter. We sell in compressed natural gas by trucks around 2 to 3 million a day. The pipeline gas sales would probably not be until the beginning of 2013. I'd say next year is focused on developing and building pipeline sales the following year.

Okay. And is it still -- for Colombia, for exploration, including the La Vega Este-1, is there 4 -- did I get this right, you still have 4 exploration wells for the second half this year? I'm not sure if I have that right.

5, I believe. There's one in the Middle Magdalena, one in the Llanos Basin and 3 in the Putumayo. The Rumiyaco, Melero, La Vega, Pacayaco-2 and Turpial.

Okay. So we have 5 distinct ones, all kind of waiting to see the outcome of those in second half of this year.

[Operator Instructions] Your next question will come from the line of Nick Coutoulakis with Cannacord Genuity.

I guess just 2 quick questions. One, timing of Moqueta-5 flow rates. And then, secondly, regarding your assets in Argentina picked up through your acquisition of Petrolifera, just the timing of these 6 development wells. How many workovers have been performed to date by you guys? And then also what sort of production potential do you see there? I know you talked about maybe potentially a little bit of growth by the end of the year. I was hoping you could paint that picture for me, please.

The test production for Moqueta-5, we expect to drill in June or July sometime, for Moqueta-5, for the test production -- I'm sorry, I think Moqueta-6. Moqueta-5 testing, we should have it in the next couple of weeks. We're doing some preliminary testing now and we'll actually begin more definitive testing once the pipeline is up and running in the next couple of weeks from now. So Moqueta-5 will have results in late May timeframe for Moqueta-5. The other question is when are we going to get the production up to what have we done so far on the Neuquen assets in Argentina. We've done approximately 5 or...

No. That's 16.

Out of the 16 planned, we've done 5 or 6 now. If the drilling haven't started, that will be ongoing sort of back-to-back through the second half of the year. In terms of a production target, we don't have a specific number. But today, it's around 2,000 barrels of oil, 2,300 equivalent. We'd like to get up to 2,500 to 3,000 barrels a day, something like that at year end.

Your next question will come from the line of David Dudlyke with Stifel, Nicolaus. David Dudlyke - Stifel, Nicolaus & Co., Inc.: A number of different questions. First of all, I was intrigued by the commentary regarding the strategy wells in Putumayo-10, Piedemonte Norte. They won't be drilled this year due to lack of appropriate slim hole rigs. These wells were marked down for the second half of this year as recently as your April presentation. Can you walk me through what has changed your expectation? And I guess given that these -- certainly, these wells have been in the pipeline for a little while. Why we don't have the appropriate rig available?

We were considering using the slim holed rig that the ANH is using for their strat drilling in other parts of Colombia. And that's not available to us. And to use a conventional rig, we're not able to get the environmental permits to do that. It's a much larger footprint. It was actually a combination of 2 or 3. One is the rig availability, and the other is the environmental permitting. We're not able to get environmental permit this year for a conventional rig. David Dudlyke - Stifel, Nicolaus & Co., Inc.: Okay. But essentially, your expectation was that you would assume the ANH rig and that has proved unlikely this year.

Yes. David Dudlyke - Stifel, Nicolaus & Co., Inc.: A question for Martin perhaps. You reported G&A of $13.6 million for the quarter, notwithstanding the fact that you've essentially taken over Petrolifera, but also there was some one-off costs, no doubt, with the acquisition. Can you provide some guidance as to what you think you can compress the combine G&A back down to on a run-forward basis?

We're still looking at about just over $9 a barrel for the year actually. That's our current estimate, $9. David Dudlyke - Stifel, Nicolaus & Co., Inc.: Okay. And then can you perhaps explain to me the $32 million write-down, the impairment for ceiling test in the Peru cost center? I'm trying to get my head around that. But if you can just at least explain where that stems from?

That comes from $15.6 million for the Kanatari well and we've also written off some seismic and area magnetic geographic survey on Blocks 122 and 128. David Dudlyke - Stifel, Nicolaus & Co., Inc.: Okay. So that speaks to not only the results for the well but also the I guess the switching of priorities away from those blocks to your other blocks within your portfolio. Okay. And last, if I may, Brillante, I'm looking at the presentation, how long a pipeline would you have to build from Brillante given the disappointing results in San Angel. You proposed to build the pipeline southeast down to the GGI pipeline. Is that still the case?

There's 2 different pipeline options. Say it's 40 kilometers, same thing 50 -- I'm saying 40 to the southeast, to the GGI pipeline. Let's compromise, say, 50 kilometers. So what is your question? David Dudlyke - Stifel, Nicolaus & Co., Inc.: Essentially, what is the minimum scale of discovery? I see the reserve that you talked for Brillante but essentially, have you got enough to merit the building of a pipeline or do you need the second well to prove up some further results?

I think that the 30 BCF is marginal, which I believe is about what we have proved at 3P around 110 BCF. Including prove up 70 or 80 BCF, we'll have it very robust. Is that good enough for you?

Your next question is a follow-up from the line of Martin Molyneaux.

Gentlemen, can you just walk us through this equity tax calculation that has resulted in the $8 million charge in the first quarter?

Yes. So, it's assessed on our equity value of our Colombia branches and whichever you want, so basically for the calculation of what our balance sheets were in our branches when we apply the 6.2% tax. As I mentioned, it's payable over 4 years. But for accounting purposes, we need to recognize it in the first quarter when we first calculated the tax.

Okay. So 4 years ago, in the first quarter, you would have done the same thing?

That's my understanding, yes.

Your next question is a follow-up from the line of Jaime Somerville.

My question's actually been answered already. Thanks.

Gentlemen, there are not further questions at this time. Please continue.