Good afternoon, ladies and gentlemen, and welcome to Gran Tierra Energy's results conference call for the quarter ended March 31, 2013. My name is Tuanda, and I will be your coordinator for today. [Operator Instructions] I would like to remind everyone that this conference call is being webcast and recorded today, Monday, May 6, 2013, at 4:00 p.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 in 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 for the quarter ended March 31, 2013, filed with the Securities and Exchange Commission, May 6, 2013. 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 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 operation. The press release disseminated by Gran Tierra Energy this morning 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 this 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 a 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, sir.

Thank you, Tuanda. Good afternoon, and thank you for joining us for Gran Tierra Energy's First Quarter 2013 Results Conference Call. With me today is Shane O' Leary, our Chief Operating Officer; and James Rozon, our Chief Financial Officer. This morning, we disseminated a press release that include a detailed financial information about the quarter. In addition, Gran Tierra Energy's 2013 report on Form 10-Q for the 3 months ending March 31, 2013 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. James will discuss key aspects of this quarter's financial results. Shane will then take a few minutes to provide an operations update, and I will then return to provide a budget update and closing remarks. Gran Tierra Energy is pleased to start the year with a major new oil exploration well success in Peru, record levels of production and associated record revenue and funds flow from operations. Quarterly oil and natural gas production, net after royalty and adjusted for inventory changes, was 23,424 barrels of oil equivalent per day, an increase of 40% from the comparable period in 2012. Alternative transportation arrangements to minimize the impact of pipeline disruptions in Colombia, a decrease in oil inventory in Colombia and production from new wells in Colombia and Argentina all had a positive impact on production. Production before inventory adjustments in April averaged approximately 22,000 barrels of oil equivalent per day, net after royalty, affirming our pipeline disruption mitigation plans are fully operational. On the exploration front, in February 2013, we announced the results of the Bretaña Norte exploration well in Block 95. This discovery has the potential to add substantially to the growth of Gran Tierra Energy in the years to come. The 1,984 barrels of oil per day test of 18.5-degree API oil gravity far exceeded our expectations. Given this success, we nearly drilled a horizontal sidetrack well extension to the existing well and are in the process of preparing to test this extension. In addition, we have added a 2D seismic program over the discovery to this year's budget. This program will extend to the south, while we have another exploration prospect we look to further define for future exploration drilling. Concurrently, with all this, we are evaluating full-field development options and anticipate first long-term test production from the Bretaña Norte field in early 2014. With revenue of $205 million and funds flow from operations of $109 million in the quarter, our balance sheet continues to be strong. Cash and cash equivalents were $236 million at March 31, 2013. We remain debt-free, and we continue to expect to fund our capital programs with cash flow and cash on hand at current oil prices and production levels and potential periodic draws from our revolving credit facility, if needed. Now let me turn the call over to James Rozon to discuss the financial results. James?

Thank you, Dana, and good afternoon, everyone. Our operational success last year has translated into another quarter of financial success, allowing us to retain a strong balance sheet to continue funding our growth strategy. Revenue and other income in the first quarter of 2013 was $205.4 million, a 32% increase from 2012 due to increased production, partially offset by decreased average realized oil prices. The average price received per barrel of oil decreased by 6% to $99.17 from $105.36 in 2012. During the first quarter of 2013, 28% of our oil and gas sales in Colombia were to a customer where the realized price is adjusted for trucking costs. The effect on the Colombian realized price was a reduction of approximately $5.10 per barrel to $103.08 per barrel as compared to delivering all of our Colombian oil through the OTA pipeline. Operating expenses in the first quarter of 2013 were $41 million or $19.46 per BOE compared with $24.5 million or $16.07 per BOE in 2012. The increase in operating expenses primarily occurred in Colombia, where there was a $13.5 million increase over the prior year. The increase in Colombia was mainly due to a change in sales point, resulting in OTA pipeline transportation costs now recorded as operating cost versus a reduction of revenue effective February 1, 2012, increased G&A allocations to operating cost and new wells with higher operating costs. The estimated net effect of OTA pipeline disruptions on Colombian transportation cost for the 3 months ended March 31, 2013 was neutral. The increased trucking costs to an alternative pipeline were mainly offset by the absence of OTA pipeline charges relating to both these volumes and the volumes sold at the Costayaco battery. The trucking costs associated with the volumes sold at the Costayaco battery were a reduction…

Thanks, Shane. So largely, due to the success experienced so far in 2013, we have increased Gran Tierra Energy's capital spending program for the year to $424 million from $363 million. The revised budget includes: $218 million for drilling; $73 million for facilities, pipelines and other; and $130 million for G&G expenditures. Of the $218 million allocated for drilling, approximately $100 million is for exploration, and the balance is for appraisal and development drilling. The majority of the increase is in Peru related to drilling the sidetrack extension to the original Bretaña Norte well, along with a new seismic program intended to provide additional details on the Bretaña structure to assist with full-field development planning and to further define the previously mentioned independent exploration prospect to the south. Gran Tierra Energy continues to anticipate production of 20,000 barrels of oil equivalent per day, net after royalty, or approximately 15% growth over production in 2012. Now this includes a 10% contingency for transportation downtime in Colombia, which we have had great success mitigating in the first quarter of this year. In the first 3 months of 2013, Gran Tierra Energy has discovered substantial new resources in Peru, attained record levels of production and delivered excellent financial results. These results are an outstanding start to the year and provides substantial support to the long-term growth of the company. I look forward to communicating our continuing success, as we proceed through the coming year. Now that concludes our prepared remarks for this afternoon. We would now be pleased to answer any questions you might have. Tuanda?

[Operator Instructions] Your first question comes from the line of George Toriola with UBS.

I've got a couple of questions. The first is on Bretaña. What do you expect to learn from the short-term test? Could you sort of go through the key learnings that you expect from the short-term test?

From the short-term test in -- coming in May, it will be a -- understand a little bit about the productivity of this portion of the reservoir that we've just drilled, understand a little bit about the pressure decline -- or the pressure decline and the pressure recovery in the reservoir, as a result of the test. So those will be the 2 main factors in the short test. And then, the long-term test, which we intend to initiate beginning of next year, will be more of the same, but over a longer duration.

Okay. That's helpful. And then, in terms of field definition, what -- are you expecting to drill step out so -- for the appraisal wells between now and when you initiate the long-term test?

No, we intend to release the rig, the current rig, after this short-term test. And then, we are planning now for an appraisal well to be drilled on a completely new location at the southern end of the structure late next year -- sometime in the second half of next year.

Second half of '14?

Yes.

Okay. That's helpful. And then, maybe just in terms of operating costs, what -- can you sort of -- and I think you guys talked about the increase in operating costs and some reclassification of costs as well as the higher volumes. Now all of your current production volumes, are you -- how much of that is -- how much of that goes through the pipeline?

Well, it all varies. The amount going by truck and amount going by pipeline varies. Some days, 100% of it is by pipeline. When the pipeline is down, the main pipeline, say, in Colombia we're talking about, then we have alternative pipeline transportation into Ecuador, and that is supplemented by trucking. So it's quite variable depending on the status of OTA.

Okay. I guess, maybe, I should ask it differently. Going forward, what do you expect your per unit operating costs would be? What would you see as a more normalized type of operating cost per barrel?

Well, normalized, I would just suggest what happened in the last quarter, first quarter of this year would be the normal cost given the current environment we're working in.

Okay. And then, last question is just -- you continue to maintain your 20,000 barrels a day, net after royalties. And based on what April was, is that suggesting that you're forecasting for declines from here or you're just building contingencies that may arise out of the pipeline?

Yes, the -- going forward, we're expecting -- well, we're still budgeting for 20,000 barrels a day, assuming the 10% contingency downtime. Now we have these mitigation programs in place that has been overcoming the downtime. So at this point in time, we're not changing our outlook. Although, obviously, for the last 4 months, we have been mitigating that downtime. So this is some of what we look at as the year evolves.

Your next question comes from the line of Nathan Piper with RBC Capital Markets.

A few questions from my end. And first of all, on Peru, I'm trying to have another go at just assessing the potential of what you've already discovered. If you are going to proceed with the field study, clearly, you must have a vision of how big the field already is. And I know that you've highlighted a contingent resource number that was used prior to the wells being drilled that you just completed and tested successfully. I mean, is that a historic number now? Or what's the sensible way of thinking about the potential that you think you've already clarified and you'll put field study together for? And what's the upside from here?

Well, I mean, we're confident of the commercial project here. The contingent resource numbers that we published were numbers from the original Amoco well drilled in mid-'70s, do not include numbers from the more recent Bretaña discoveries, Bretaña Norte. We found better reservoir quality than we expected, better oil quality than expected. So I think those numbers are somewhat outdated. They're conservative. And we're very aggressively moving forward to get more reflected reserves booked by year end.

Well, what's the basis for your field study? What field size are you going to base your field study on?

We can do several different field sizes. So there's going to be a range of different field sizes in the study.

And you're not prepared to give that range anytime?

Not right now, I guess.

All right. And so, second question then. On Moqueta, just to understand the implications of Moqueta-9 results, I mean, there's been -- Dana, you've defined the northern extent as a nice way of saying -- well, potentially saying [indiscernible] high much more. And in the context of the GLJ reserves [indiscernible] Moqueta-9 results back up?

I don't think it really impacts our GLJ reserves or year-end reserves at the end of last year. The reserves, they're really based on existing well data at that time. So we're still looking at, well, additional resource potential -- or additional reserve potential down-dip to the west, to the south and then eastern flank of the structures not yet defined by the drilling. We're not expecting any negative impact on the year end reserves from last year.

Okay. So it's confirmational rather than additive. Is that fair?

That's correct.

Okay. And then last question, on Brazil, I think [indiscernible] the 14th and 15th [indiscernible] supposed to go on the 14th and 15th this month. Is that approximately the timing when we would hear more on the test results from Recôncavo Basin? I mean, I do know that the [indiscernible] keep picking up so you've got made commercial discoveries there -- or [indiscernible] next discovery there. But clearly the test rate, what's -- what are we waiting for? I mean, have you completed the operational work on that and just waiting for the right time to release the information, or are you still working on those wells?

No, it's still early days with the wells. So the -- I don't think we'll be putting out news, I don't think, until we get the 3 wells drilled, frac-ed and then tested, and we're only halfway through that program. So I think, by the time we get the third well done, it will be in mid-year. So it's not just waiting for the [indiscernible].

That fair enough. You'd rather just put them together because that's going to aggregate program that's relevant rather than individual wells?

That's correct.

Your next question comes from the line of Matt Portillo with Tudor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just a few quick questions for me. In terms of Costayaco, we continue to see production holding up quite well. I was just curious if you can give us an update on water injection and how you guys think about plateau production levels from here and maybe any color on timing of when we could potentially expect to see some of those production declines kicking in?

We continue to ramp up the water injection at Costayaco. I think we're up to around 26,000 barrels a day. But I mean, ultimately, we're trying to get up to 40,000. So we're continuing, as part of our regular drilling campaign, to drill both water injection wells and production wells and are looking at some stimulation techniques on other wells to increase the injectivity of water, and we're building another pump station for water and treatment facility and so on. So water injection is continuing and continues to be very effective. We've always predicted Costayaco plateau would come off sometime. I think we're sort of looking into next year now. But we're not expecting to see any declines from Colombia because Moqueta continues to ramp up. And the only thing really standing in the way of increasing Moqueta production at this point, we have enough wells into the field now, is water injection. We have to get more water into the reservoir at Moqueta, and then we can increase production rates from that field. So this is this all going to happen in parallel, and we don't expect to see declines next year in Colombia. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And I guess, as we think about kind of the development well you guys just drilled, was that a booked reserve in terms of -- was that a well you planned to encounter oil in, or was that something you're drilling as a water injector and you found oil? I'm just trying to get a little more color on that?

I don't expect to see any reserve increase. You're talking about Costayaco? Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: 18.

17 or 18? 18. No. I mean, that's part of the field. It's within the field boundary. And so, I wouldn't expect to see -- and there might be some minor adjustments, but nothing material. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then, just with Moqueta, the structure. I think kind of in the blue sky scenario, previously, you'd kind of potentially thought of it as a 30- to 40-million barrel type structure and kind of the blue sky case. Has that picture changed at all with what you learned on Moqueta-9? Has that removed any of that upside, or do you still see the potential to move the resource size up over time?

I don't think our numbers are quite as big as what you are quoting there, but, no. If you recall the Moqueta field structure, we were trying to prove up reserves underneath the major fault to the north. I wouldn’t say we completely condemned that concept, but it's much more complicated than we were expecting. And it's not something we would test again in the near term. We would wait, and we have other priorities for the field. So we -- as we said, we define the northern limit to the field, as we know it today, with the current drilling we've done. Shane P. O’Leary: But the other point is there's significant running room remaining potential on the eastern flank, which is yet to be drilled. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then, just on Moqueta, in terms of the production ramp-up, how should we think about, kind of, the plateau production levels you guys are envisioning under the current development plans, kind of, in 2014, 2015? I'm just trying to get a better sense of how should we be thinking about that production profile going forward.

Well, we have a productive capacity right now to produce almost 5,000 barrels a day. But we're not there because we need to get more water injection going. So that's our priority for this year. If some of these higher reserve numbers are proven up as we go forward, we've thought about getting up as high as 70,000 barrels a day, but that's still conceptual. We still need to drill more wells in -- as Dana was talking about, in the eastern part of the field, in the southern part of the field. And we need to really define the limits of the reserve estimate before we can really talk about ultimate numbers. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And just my last question. On Llanos-22, you guys have just started up production. I think that's under a fairly constrained rate. You mentioned that you are looking at compression and some additional gas takeaway. How should we think about the production profile on that well? And are there any additional appraisal wells that you plan to drill this year or any exploration wells on the block? I'm just trying to get a sense of, kind of, the productive capacity from that area over the next 6 to 12 months.

Well, we're currently flaring gas -- the associated gas, and we have a flaring restriction. I think we're around 1.3 million a day or something like that. What we're looking -- what we're trying to do is tie in to the Techion [ph] facility, and we're actually looking at a compressed natural gas trucking scenario, where we can get, in the short-term, volumes to their facility transported by truck, which would allow the operators, perhaps, to increase the volume from the current test. So that's ongoing, and it's something that can be done in the fairly short term, assuming everything goes well. Longer term, you'll recall that the well tested in excess of -- I think, it's around 2,500 barrels a day. So, yes, we are severely limiting the test volume right now. But there is a well planned for next year at the -- an appraisal well that we're nearing construction.

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

I'm just wondering. Dana, you obviously -- a strategic question. Your cash position tends to be very positive and, in fact, growing a little bit. Just your thoughts as far as acquisitions. You currently obviously have a fair amount of acreage already. But then just your thoughts, number one, on sort of CapEx given that sizable cash position you have. And then, besides, I guess, CapEx, looking at what you think about dividends or repurchase or how else maybe you give back cash that way?

Yes. So acquisitions, we're constantly on the lookout for acquisitions in different forms farm ins, asset acquisitions, corporate deals. But as you know, we have a very large land position and a very strong asset base that we're confident we can keep growing the company with. So for us, to do any kind of acquisition, it has to be extremely compelling. And we just don't see many compelling stories out there that we think could actually add value to assets or lands that are more attractive than our existing lands. So we continue looking, but it's tough to find something that we like more than our own existing acreage. Now you note our strong cash position, it's historically been strong. We are, I guess, on an ongoing basis, due to the dividends and other alternatives, due to the stock, but the reality is, given our success, given our growing capital demands, we think this money is best kept in reserve to invest in our existing lands. There's some major projects that are developing in Gran Tierra, and we want to be able to execute on those projects with timely fashion. So at the moment, our plan is to keep investing in the company.

Fair enough. And that is a great answer. And then, I'm just wondering, you mentioned about the large lease position that you have, Dana, but I was wondering, I guess, more specifically, where you're not quite as active in, I mean, you're starting to become more active in Peru. But just wondering, even if you say, look at Argentina, is there any issues there with holding leases for the remainder of this year?

Well, in general, no. In general, all our leases do have expiries. So we do have undertaken a certain amount of work on our leases in a timely fashion. So I wouldn't say there is any significant lease [indiscernible] on any of our land. We are doing the work. Some of our contracts in Argentina, we are -- they do expire in 2015, 2016 timeframe. So we are renegotiating some more commitments on a few of those blocks to get a longer -- get extension to the periods that we hold that land.

Got it. And then, just lastly. I was wondering about -- with this position, what's your thoughts on hedges and having more hedges at this point?

No, we have no hedges in place on any of our traction, and we don't have any plans to hedge.

Your next question comes from the line of David Popowich with Macquarie.

You mentioned a couple of times that the Moqueta structure holds additional potential to the east. I'm just wondering when you think you'll be able to appraise this? And then probably a related question is, how many more wells do you have permitted at Moqueta right now?

Yes, that's the challenge. Right now, we have 2 locations permitted, and we're doing all our drilling -- these 10 wells now that we drilled, we are drilling from these 2 individual locations. So we're drilling deviated wells, long ridge wells trying to define the edges of the field. What we're waiting for is global environmental permit, which will allow us to drill wells anywhere we want in the optimum locations, either as producers or appraisal wells or water injectors. Because the location of these 2 appraisal licenses that we're drilling from, we can't reach the eastern flank of the structure, eastern 1/3 of the structure. So we're waiting for this global environmental permit, then our current understanding is that it should get approved in the -- early in the first quarter of next year. So hopefully, we'll get that approved early next year. That will then allow us to begin lease construction and then undertake drilling through next year to finish the appraisal and initiate infill drilling.

Your next question comes from the line of Ian Macqueen with Gran Tierra.

Actually, to follow up on Dave's question. As far as I understand, that global environmental permit is delayed, and I was expecting it might be late Q3 or early Q4. Is that correct?

That was probably our most recent outlook. I mean, the reality is, when we made the discovery, we thought we would have it a year before and I'm expecting it. So there's been a series of questions and answers, back and forth. We have now fully satisfied all of their questions, so there's no more work to be done. We received official notification of this just a few weeks ago. So there's a, call it, definitive clock now ticking, which allows us to say early first quarter.

Okay. Good. My question really revolves around both Brazil and Peru. Obviously, a lot of excitement involved with both of those assets, also a lot of capital. What's your current thoughts on farming out -- I guess, part of the idea of farming out is to distribute risk, and the other thing is to distribute capital exposure to a partner. So what's your thoughts on either Bretaña or other assets in Peru as far as farm out goes and the same thing for Brazil?

Particularly, when we look at the farm outs, we would typically bring in partners on exploration projects versus [indiscernible] projects. And that's not just to reduce risk, but just to reduce our capital exposure to risk -- reduce our capital risk. So -- and that's our general philosophy, is farm out exploration and not reserves for contingent resources, same with Bretaña. So we're probably always open to different options. So on all of our projects in the company, we look at different strategic initiatives. Bretaña has still relatively long time till we get to plateau production with a lot of capital upfront. So we might consider partners there at some point, but no definitive decisions have been made.

Okay. So Bretaña maybe, and the rest there -- you still have lots of acreage in Peru. Are you actively seeking any partners for that at this point?

Most of our exploration acreage, we're open to having partners. So...

Okay. So open to the idea, but nothing definitive. And then, in Brazil, can you comment on that?

We're not looking for partners on our land now.

Your next question comes from the line of Josef Schachter with Schachter Asset Management.

Can you shed some light on the exploration side for the Moqueta deep and for the Miraflor West-1 well, the time of when they'll go, the depths that you're looking at and the size or price? Can you maybe shed some light on those?

Yes. The Miraflor West day or the Miraflor East is -- should start growing a month from now. We're just finishing up the location, have not yet started the rig mobilization yet. But that will be drilled, probably a second quarter well. Moqueta deep will be later in the year. That's late third quarter or early fourth quarter. In terms of resource potential, these are sort of more typical Colombian-type prospect sizes, pinnings, 4, 5, 6 million barrels or so.

And the depths there?

Oh, depths. Miraflor West is 8,000 feet, I think. Moqueta deep, 6,000 or 7,000 feet. So they're not deep wells. They're not unusually deep.

Gentlemen, there are no further questions at this time. Please continue.

All right. Well, I'd like to thank everyone for joining us today, and we look forward to updating you on our progress through the year. Thank you for your time.