Good afternoon, ladies and gentlemen, and welcome to Gran Tierra Energy's Results Conference Call for the Quarter Ended June 30, 2013. My name is Jeanetta, 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, Wednesday, August 7, 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 June 30, 2013 filed with the Securities and Exchange Commission, August 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 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, you may proceed.

Thank you, Jeanetta. Good afternoon, and thank you for joining us for Gran Tierra Energy's Second Quarter 2013 Results Conference Call. With me today is Shane O' Leary, our Chief Operating Officer; and James Rozon, our Chief Financial Officer. Just so you know, we disseminated a press release that included detailed financial information about the quarter. In addition, Gran Tierra Energy's 2013 report on Form 10-Q for the 3 months ended June 30, 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 developments for the quarter; James will discuss key aspects of this quarter's financial results; and Shane will then take a few minutes to provide an operations update. I will then return to provide a budget update and some closing remarks. Gran Tierra Energy has just delivered another strong quarter of production. Quarterly oil and natural gas production net after royalties and adjusted for inventory changes was 22,131 barrels of oil equivalent per day, an increase of 57% from the comparable period in 2012. Before inventory adjustments, production in July 2013 averaged approximately 23,000 barrels of oil equivalent per day net after royalty. Due to the record production of 22,725 barrels of oil equivalent per day net after royalty adjusted for inventory changes experienced in the first half of 2013, Gran Tierra Energy is increasing its production guidance for the year to range between 21,000 and 22,000 barrels of oil equivalent per day net after royalty and before adjustments for inventory changes, an increase from the company's prior production of 20,000 barrels of oil equivalent per day net after royalty. Approximately 96% of this production consists of light oil and the balance is natural gas. Revenue and other income for…

Thank you, Dana, and good afternoon, everyone. Our operational success 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 second quarter of 2013 was $168.8 million, a 47% 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 8% to $85.03 from $92.48 in 2012. During the second quarter of 2013, 51% of our oil and gas volumes sold in Colombia were to a customer where the realized price is adjusted for trucking costs relating to a 1,500-kilometer route. The effect on the Colombian realized oil price was a reduction of approximately $11.30 per barrel to $86.61 per barrel, as compared to delivering all of our Colombian oil through the OTA pipeline. Operating expenses in the second quarter of 2013 were $31.9 million compared with $27.3 million in 2012. The increase in operating expenses was primarily due to increased production, partially offset by a decrease in the operating cost per BOE. On a per BOE basis, operating expenses decreased by 25% to $15.84 from $21.26 in 2012. Operating expenses per BOE decreased in 2013 primarily due to OTA transportation costs and other trucking costs not incurred for those volumes subject to alternative transportation and arrangements. For these volumes, ownership is transferred at the wellhead and the associated transportation paid by the purchaser is netted to arrive at our realized price. The estimated net effect of the OTA pipeline disruptions on Colombian transportation costs for the 3 months ended June 30, 2013 was a saving of $2.20 per BOE. Depletion, depreciation, accretion and impairment, or DD&A, expenses in the second quarter of 2013 were $63 million compared…

All right. Thank you, Shane. Gran Tierra Energy's planned capital program for its exploration and production operations in Colombia, Brazil, Peru and Argentina for 2013 has been revised to $454 million from $424 million. This includes $216 million for Colombia, $94 million for Brazil, $33 million for Argentina, $109 million for Peru and $2 million associated with corporate activities. The majority of the increase associated with Gran Tierra Energy's capital spending is due to the Brazil Bid Round, drilling the Proa-3 well in Argentina, the increased costs associated with the successful horizontal sidetrack well in the Bretaña structure in Peru. The capital spending program allocates $235 million for drilling; $72 million for facilities, pipelines and other; $129 million for geologic and geophysical expenditures; and $16 million for acquisitions. Of the $235 million allocated to drilling, approximately $124 million is for exploration and the balance is for appraisal and development drilling. The 2013 program currently contemplates the drilling of 7 gross wells in Colombia, 4 gross wells in Argentina, 3 in Brazil and 2 gross wells in Peru. The approved 2013 capital spending program also includes funds for 1,302 kilometers of 2D and 200 kilometers of 3D seismic acquisition programs in Colombia, Peru, Argentina and Brazil in preparation for additional exploration and production drilling operations in 2013 and beyond. The 2013 work program and budget is expected to be funded primarily from cash and cash flows from operations at current oil prices and production levels. In the first 6 months of 2013, Gran Tierra Energy has discovered substantial new resources in Peru, attained record levels of production and delivered excellent financial results. These record results for the first half of 2013 are providing substantial support to the long-term growth of the company. With visible production and reserve growth on existing discoveries and substantial exploration drilling on our lands pending, the future continues to hold exciting potential for our stakeholders. 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. Operator?

[Operator Instructions] And your first question comes from the line of Caio Carvalhal with JPMorgan. Caio M. Carvalhal - JP Morgan Chase & Co, Research Division: I have a couple of questions, but I will limit it so I can give a little space for my colleagues. So the first question would be -- it would be very specific. We understand that a part of the lower realization price was due to the higher trucking volumes. And that was a consequence of the low -- of the high -- the too many days of interruption in the pipeline. So my question would be, I mean, up to now, could you share how many days of pipeline interruptions do we have so far in the third quarter? And I know it's kind of unpredictable, but could you -- do you believe that based on your contact with the local communities, if we are likely to see third quarter with as many days of pipeline interruptions like we had before? And also from net to debt, I understand that trucking oil was one of a few contingency measures that we were addressing. Another one, I remember, was increasing the pipeline capacity and the storage capacity. I would like to know if there is some further potential benefit from these other alternative measures that would reduce the pipeline -- sorry, the trucking usage. And I apologize for the long question, but that's one question. The second question refers to Peru and the expected production test. Is there any environmental permits or any regulatory impediments that you are still waiting for the test? Or everything is ready, and it's just a matter of time to start the test? Those are my 2 questions.

Yes, for the downtime for the third quarter, which is basically July, I don't have the exact number of days. There has been some additional downtimes. But currently, all the pipelines are up and running. We've got a forecast going on and we are expecting to continue to having disruptions on the pipeline. It's not related to the communities. We're not having community issues. But of course it has to do with -- I guess the guerillas up in the high mountains in the Andes. So we continue to expect to have disruptions, but as you know, those have been mitigated to date. We do have alternative pipeline to us and we are using that. And that is into Equador from the Putumayo Basin. And as that continues to mature in terms of right [indiscernible] capacity, that will also assist with decreasing trucking volumes. Turning to Peru, there are a variety of additional permits that are required for the transportation of crude on the rivers in addition to building some of the facilities we're going to build on the platform. At this time, those are not limiting factors on initiating our long-term test. Now we're still in early days of designing facilities to handle the crude as well as contracting barge for the transportation of the crude. So yes, there are more permits, but those are not the staging items at this time. Caio M. Carvalhal - JP Morgan Chase & Co, Research Division: I understand. And just a follow-up on the Peruvian information. So there's a couple of permits and do you have an estimate of time when that will be ready or based -- or these -- and I apologize if the question doesn't make sense, but does this regulatory terms that you're still waiting, are those sort of on the complex side or these are more easier to get and it should not be a problem? What is your view on that?

Yes, that plan again is to initiate the long-term test in the first quarter of next year and we don't have a specific date, but in the first quarter. These are, I'll call them standard permits that other operators have applied for and have been granted in the past. So we're not foreseeing any significant issues with obtaining the permits. They're what I would call conventional permits for handling crude in Peru.

Your next question comes from the line of Jamie Somerville of TD Securities.

I thought I'd maybe just follow up on the last question. I think Caio was asking about -- whether you're using the increased storage and increased capacity on the OTA, when it is up and running to deal with the pipeline disruptions yet or whether you're just relying on alternative routes?

Basically, we're relying on alternative roots. We have, I guess, I'd say, lesser need of the storage at this time because we have so many options, so much flexibility in transportation. And Shane or James can correct me, but I believe right now, our storage levels are at minimum levels right now. So we have maximum storage available to us at this time.

Okay. And you've done the analysis and concluded that using those alternative routes is more cost-efficient even though you would get better netbacks exporting through the OTA?

Right.

Okay. So just thinking about -- I know you probably haven't thought about the budget for next year. But wondering if you can give some directional guidance. Is it fair to assume that your overall budget is likely to remain -- spending levels are likely to remain relatively flat, but that you're probably going to see continued focus on Brazil and Peru due to the commitments that you've made there and potentially declining focus on Colombia?

That's only partly true. I think -- again, we don't have a budget for next year. But it would be safe to assume it can be consistent with this year, flat year-over-year. I would expect that -- but not necessarily expect -- growing capital spending in Brazil as a result of our new lands. We'll continue evaluating resource play and then we'll start acquiring our seismic program on the new acreage. So the spending associated with that in Peru, again we're planning on starting -- well, the long-term test, but also starting the process around the appraisal well in the far south. So between those 2 spending levels in those countries, it'll probably end up being the same as this year, not an increase. And the for that matter, the same will apply for Colombia and Argentina. I think the breakdown by country will be probably consistent with this year --

Okay. If I may, in Brazil, are your newer lands focused more on the tight oil play or on the shale play?

On both. And it's something we just now start talking about and one of the reasons for taking up this land is the fact that we actually have 2 plays. The tight sands and the shale oil or oil shale plays that you mentioned. So it's really chasing both plays on this larger expanse of land we have available to us.

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, I was wondering if you could give us an update on how the reservoir is performing versus your expectation. Has there been any change to kind of your timeframe for when you expect the reservoir to start to decline from a production perspective?

No, it continues to do extremely well. I'll let Shane speak to it, but the water injector is going well, the production is doing fantastic. So it's continuing to perform very well, but maybe Shane can expand on that. Shane P. O’Leary: Yes, I mean, the water injection program -- water plug program we have I'd say is textbook. It's -- we're seeing a fantastic pressure response in both the T-sand and the Caballos reservoirs. We're now injecting about 26,000 barrels a day of water into the flanks, the flank of the structure, and the sweep efficiency is extremely high. And we're going to ramp that up probably by the end of the year to about 34,000 barrels of water per day. So continuing to build up pressure. It's hard to say when decline will come. We continue to be surprised on the upside. And Costayaco continues to overachieve. Sometime next year would be our best guess, but it's very difficult to say. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then, I guess that -- with that commentary in mind, is there -- I guess, upside -- additional upside potential just from the recovery factors versus what you've been given credit so far for from a reserve auditor perspective? Shane P. O’Leary: There's still some. Every year, if you look -- sort of look at the history of Costayaco, every year, we've had technical revisions upward because the reservoir continues to produce much better than the reservoir models are predicting, or the reservoir models that the reserve auditor are using. And so there is still some -- the 3P is still higher than the 2P, which is higher than the 1P. And so, over time, those -- all of those categories will collapse into one another and we think we'll achieve the ultimate 3P of the field, which is around 60 million barrels gross.

Another part for that is we've begun studies on some EOR, and that's for recovery technologies or applications for the field. So those studies are just now starting, but again, if we can show potential there, success there, then that can add additional incremental reserves as well. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And then just on the permitting side. Just wanted to get an update in Colombia how the permitting process is going for both your development assets and also on the exploration front. And if you've seen any real material change thus far in the permitting process in country?

I'd say we haven't seen any real material decrease in time for the award of the various permits. I think we're no longer seeing the increasing delays. So I think they're sort of reached the point where they're able to -- keep pace with the permit applications. Declines are not continuing to slip. But having said that, they are slower than years past, but they don't seem to get any worse, they've reached a steady state. But we are hoping to still see speeding up of the approvals going forward. But really haven't seen a material change in that regard yet. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Great. And just last question for me. In regards to Argentina, I was hoping that you could provide a little bit of color on how you guys are thinking about that asset within your portfolio today? And maybe some of the medium and long-term plans from an investment perspective, given some of the political constraints in country?

Yes, we continue to look at Argentina's option value. We see good geological potential there. Argentina does have good fiscal terms, attractive fiscal terms. Of course, the macroeconomic policy in the country, because of that we're not seeing a reflection of value in our share price when we put ballers into the country. So we consider option value. What we are doing is reinvesting cash flow into our operations there. Not investing new capital, certainly not the level we are in other countries simply because of macroeconomic concerns. So we continue to grow our business in-country by reinvesting cash flow, but not seeing it as a growth area for new investment at this time.

Your next question comes from the line of Jamie Somerville of TD Securities.

I just wanted to follow up. So if you're not using all of the export options that you have, as such you're not using the storage and utilization of increased capacity on OTA when it's up and running. Why should we assume that the Costayaco area is still constrained to a plateau production of 25,000 barrels a day gross or less? Or so why can't you accelerate production from that area going forward, now that you've developed these alternative export options?

It's a reservoir issue, Dana, go ahead.

Yes, I was going to say it's a reservoir issue. So we're not constrained by transportation. We're producing Costayaco at what we think is optimum rate to maximize value from the field. Moqueta, we don't want to increase production too hard because we don't have enough pressure support yet in the field with a gas cap, which means the oil is saturated with gas, which means if pressure drops in the field, the gas come out of solutions and we produce a gas instead of the oil. So it's not transportation capacity that's constraining us, it's water injection and pressure support that is constraining us at Moqueta, hence, our desire and need to drill water injection wells as soon as we can. David Dudlyke - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So the pace at which you can develop pressure support is really defining your capacity in the plateau levels?

At Moqueta, that's correct.

Okay. My other question is on the new production guidance. So you averaged over 22,000 barrels a day in the first half of the year. And if I take the midpoint of your new guidance, that would imply less than 21,000 barrels a day in the second half of the year, which I think is an annual decline rate of maybe 10%. Is that just you being conservative or is there something driving you to expect a decline in production in the second half of the year?

I think it's fair to say, we're being conservative not knowing what the future holds with our transportation options available to us. Obviously, things are working for the last 6 months, even exceeding our expectations. But we consider -- we continue to be cautious going forward and where we look at our guidance as the year advances.

Outside of unpredictable events, there's nothing in your operations that should lead us to expect decline in production in the second half of the year, is that correct?

Unless Costayaco should start declining, which we have not seen that happen yet, any indications of that, yet.

Your next question comes from the line of Pedro Medeiros with Citigroup.

I actually have 3 quick questions. I'll start with the first one. And I apologize if you have discussed about -- if you have discussed this already. But can you go over again, on the drilling campaign expectations for the Moqueta formation? And if -- are there any new wells planned for this year that are targeting to delineate the oil-water context and the potential for an even larger column?

Yes, we're looking at drilling Moqueta -- or planning for Moqueta-12, as we speak. We have 2 different bottom hole locations and the team has not yet decided which location to drill at this time, but yes, we are planning at least 1 more well this year.

Okay. And I don't know if it's too premature to talk about your objective of this well. But is it -- is the main objective to primarily delineate it and find the oil water context or...

As I understand it right now, it may be a [indiscernible] producer. We're really reaching the limits of the reach of the wells from the existing locations. So it's becoming very difficult for us to drill any further out. To find the limits in the field due to the lack of permits to drill or to build new drilling locations.

Okay. And my second question was about Brazil. Given the results you had up to now from the tests that were conducted, was there any indication from these results that have made you less or more excited with the tights in play? And are there any plans to come back any time soon to test the tight sands?

Yes. We're more excited because as we're gathering more data we've, matured a second play. This is the oil shale we're protecting right now. We do want to get back to test the tight sands. That's not going to get tested in these next 2 of the current well or the next well after that. Those are both dedicated to the shale oil, but we still firmly believe in the tight sands and we've got numerous penetrations to the tight sands and so we're going to continue maturing additional locations for the tight sand, as well as the oil shale. So we're maturing both in parallel and we're more excited because we now actually have 2 play types rather than 1 when we first started with this program.

Okay. Is there any chance or maybe this is too premature as well. But could you potentially rank the 2 given the data you have collected up to now, tight sands versus the shale?

At this point, they're equal in terms of potential, I don't know if Shane has any other opinions on that? Shane P. O’Leary: I mean, I think the tight sand will be easier to produce ultimately than the shale. But it's trickier to map than the shale. So they both have their advantages and disadvantages, I guess.

Okay. And just one last question, coming back to a question that was done before. Considering that the likelihood of an increase for 2014 budget is low, how should we think of -- about the deployment of Gran Tierra's potential excess cash flow for 2014 and perhaps, for the end of this year? Can we potentially consider or expect a dividend? Is there a room for it?

At this time, no. Obviously, we're just now doing a pre-feed, a preliminary full-field development planning for Peru, for Bretaña. We're still early days in this exploration drilling program on Brazil, which, if successful, is going to be very capital intensive. But this time, we're going to sort of stay the course, see how both these projects play out in the balance of the year. And then see what our capital demands are going to be next year and the subsequent year. Obviously, what we don't want to do is get into a dividend paying scenario where 2 years from now we can't maintain those dividends, which some of our peers have suffered. So, we -- we're going to continue to take a conservative course on our approach to our balance sheet.

Okay. Fair enough. And if I may, just have 1 actually -- 1 last question. Do you have any quick update on how are the negotiations progressing with Petrobras for the sale of oil and gas in Brazil?

Let's see. We don't have any material updates on the gas. We're -- those discussions are still ongoing. The oil sales are continuing as normal, so I won't say there's anything different there.

Your next question comes from the line of Brad Marcotte [ph] with Amber Capital.

Dan, I was wondering if you had an idea of how many onshore horizontal wells have been fractured in Brazil, sort of industry wide? And then if you can comment on how equipment availability is.

To the best of my knowledge, there's perhaps only 1 horizontal fractured simulated well ever drilled in the entire country prior to our wells. So as a result of that, and one of the challenges we face is the lack of equipment and lack of services for this type of program. So it's -- one of our considerations going forward is, if this program works, we'll obviously have to be bringing in new equipment and services to manage a long-term project with multiple wells drilling simultaneously. So it's one of the reasons that program has been so slow as it has, is the lack of quality services to support this kind of work.

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

Shane, you said that you guys hope to book reserves in Peru at the end of this year. Could you please just clarify what has to happen in order for you guys to book reserves this year? Shane P. O’Leary: Well, we need an economic project that's -- economic development that's sanctioned by the Board. And in order to do that, we need an engineering study on the cost of facilities, which we're doing through Foster Wheeler right now. We have actually 3 well bores, if you include the horizontal and the vertical in the original Amoco well, that helped define test rates and oil column and that sort of thing, which obviously, is very important to the reserve auditor, in terms of assessing reserves. And we would like to have the 2D seismic program, modern-day seismic rather than 1970s vintage, which would help with the mapping of the field. But we don't have to have that. I mean, we can get by with the old data for the purposes of reserve booking, but we would prefer and we expect to have the new seismic. So those are really the things that we need. We need to show that we defined enough reserves on a 2P, 3P basis, and we need to demonstrate that we can sell the crude, that we can get the crude to market, and that -- and then with the cost profile, this is all an economic venture and then we can book reserves.

So just to follow up. I mean, I'm not sure if you guys are in a position to share this. But just given the way the drilling program has gone this year, at both Moqueta and Peru, do you guys have any internal targets of where you see reserve growth this year?

In terms of -- not in terms of reserve targets, no. We publish continued resource numbers for Peru. Those are inactive 51-101 and then carry those should convert to reserves if the Board approves a commercial project which is what we're working towards. In terms of the Moqueta, we don't really have any guidance or direction to share at this time.

Your next question comes from the line of Justin Anderson with Salman Partners.

Question is on Moqueta-10 and 11. And specifically on this 290 feet of gross pay that you have uncovered in the Villeta, as well as the larger aerial extent than you previously expected that I believe, 10 uncovered or 11, I can't remember which. Would you classify those unexpected results as within sort of the 3P reserve estimate for the field or would that be outside of that estimate?

The last well, Moqueta-11, would be outside that area. Just outside the 3P area, I think, is what you asked?

Yes, it's outside the 3P area, but in terms of the additional pay, would that also be, like if you're looking at your 1P, 2P, 3P, would the higher pay be outside of that or within that bound?

No, even the 3P is down to the lowest known oil, so it's below that.

So it's below that. Okay. Okay, that's great. I guess just real quickly on Bretaña Norte. I mean, most of the guys have kind of hit on this already. But for me, the big question here is, what -- other than just converting the contingent into reserves, is there some-- is there some other unknowns that you're trying to get at in order to do that or is it as simple as just showing that you have an economic route?

The key factor right now is the economic question. We have a reasonable map based on the 2D. We have good quality well data. We actually have 3 separate well bores, one in the North and there's a well we drilled -- there's another well actually called the Neiva [indiscernible], just on the southern edge of the field that shows consistent reservoir. So the new 3D -- new 2D seismic -- sorry, is going to incrementally adjust the details on the shape of the structure. But it's not going to -- we don't think [indiscernible] order of magnitude, change the volume. So it's really, right now a question of cost to prove the commerciality in the field -- the development cost.

Right. And are there any analogues that the engineers are going to look for those cost estimates?

Yes, well, there's I don't know, a dozen -- maybe more than that -- at least a dozen other fields in the basin producing from this stage [indiscernible], some of our [indiscernible] reservoir. The closest field is about 100 kilometers away, which -- and that field also has similar oil quality. The other fields, some of their oils are lighter, or some are heavier. So there is a petroleum sector active here in terms of getting costs with both transportation and development costs and infrastructure, based on the other operators in the basin.

Your next question comes from the line of Darren Engels with FirstEnergy.

Just a quick question. When we look at 2014 production, is there any kind of loose guidance you can give now with respect to Moqueta potentially ramping up once the global environmental permits are received, and also with the inclusion of Bretaña and how you see that unfolding maybe starting in Q1, or the late part of Q1?

Well, corporate wise we haven't provided any guidance. It's early days at both Bretaña and Moqueta, and of course on Costayaco. There's lots of different moving parts. We're producing today at Moqueta over 4,000 barrels a day -- 4,000 to 5,000 barrels a day. So I'm sure Moqueta will be over 5,000 next year. We haven't defined a production level -- optimum production level for Bretaña yet. We test over 3,000 barrels a day. I doubt we'll test that high in the long-term test. We want to minimize water -- premature water breakthrough. So it will be at some level lower than that, 1,000 or 2,000 barrels a day. We should have some additional production in Brazil next year. If Mayalito works, we could have some additional production there. And then, of course, Costayaco may start declining sometime next year, so that's going to offset these other growth areas. So overall, we see a variety of different projects that can add production. And then the pending decline will offset some portion of that production growth. And at this point in time, it's too early to provide any realistic guidance for next year.

Your next question comes from the line of David Phung with Crédit Suisse. David Phung - Crédit Suisse AG, Research Division: So just focusing on Brazil a bit here. What was of the oil saturation that was targeted in that first well, and what do you think the new cutoff in oil saturation needs to be?

We're not providing any technical details on the work there. It's obviously a very competitive environment. We're putting a lot of effort into building a leadership position there, so the technical details we won't address. David Phung - Crédit Suisse AG, Research Division: Right. So I guess you can't comment on the deliverability that you saw added?

That's correct. David Phung - Crédit Suisse AG, Research Division: Okay. And that lower water bearing zone, is that found everywhere in that basin or is it in patches? Is it a risk everywhere you go?

It's -- well, below the package, there is obviously water zones below and above. So in any resource play, you have that risk, yes. Shane P. O’Leary: The zone is the Agua Grande zone, which we actually produce from -- in our Tiê field. It's one of the producing horizons, but where we were doing the horizontal well and the frac, we know it to be water bearing. David Phung - Crédit Suisse AG, Research Division: So do you have an anticipated date on when you're going to production test that second well?

Probably -- which well, the one we frac-ed already? David Phung - Crédit Suisse AG, Research Division: Yes, the one that you're doing remedial operations on. Shane P. O’Leary: We have to bring a certain type of packer and tubing string into Brazil. So probably not until end of September, early October.

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

All right, thank you, Jeanette. And thank you for everyone calling in. We look forward to speaking with you next quarter when we update you on our progress. Thank you.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.