Good morning, ladies and gentlemen, and welcome to the Gran Tierra Energy's Result Conference Call for the 3 months ended September 30, 2011. My name is Francine, and I am your coordinator for today. [Operator Instructions] I would like to remind everyone that this conference call is being webcast and recorded today, November 8, 2011, at 10 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 statement. Listeners are urged to carefully review and consider the various disclosures made by Gran Tierra Energy in its reports filed on the Securities and Exchange Commission, including risks set forth in Gran Tierra's Energy quarterly report on Form 10-Q filed with the SEC on November 7, 2011, and 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 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 they may be required by applicable law or regulation. Today's conference call also includes a 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 and loss, as well as information about why the management believes this measure is useful in evaluating the company’s performance, and is available on Gran Tierra's Energy 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, Francine. Good morning, and thank you for joining us for Gran Tierra Energy's Third Quarter 2011 Results Conference Call. With me today is Martin Eden, our Chief Financial Officer; Shane O’leary, our Chief Operating Officer is unable to join us today due to schedule conflicts. On November 7, 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 September 30, 2011, has been filed on EDGAR and is available on our website at www.grantierra.com. I'm going to begin today by talking about some of the key developments for the quarter. Martin will then take a few minutes to discuss key aspects of this quarter's financial results. I will then provide an operational overview and outlook followed by closing remarks. Financially, the third quarter was highlighted by revenue and other income of $151 million, net income of $49.1 million, and funds flow from operations of $72.8 million. Cash and cash equivalents were $226.4 million and working capital was $230.5 million at the end of the quarter. As before, the company remains debt free. Operationally, the third quarter was highlighted by record quarterly production of 18,369 barrels of oil equivalent per day, a 36% increase from the year before. Approximately, 95% of this, or 17,437 barrels, was light, high-quality high [indiscernible] crude oil. Gran Tierra Energy also confirmed 2 new oil discoveries, one in Columbia and one in Argentina, plus a very important appraisal well with Moqueta-6 in Colombia, which has confirmed additional oil volume in this growing oil discovery. Perhaps most importantly, we've expanded our strategic partnerships in South America where we have entered into agreements with Statoil and Petrobras in a joint venture to explore in the offshore of Brazil and expanded our existing partnership with CEPSA to explore additional prospective acreage in Colombia. Both of these initiatives add new, large exploration prospects to our exploration inventory with both near-term and long-term drilling opportunities. Before going into more detail, let me now turn the call over to Martin Eden to discuss the financial results. Martin?

Thanks, Dana. And good morning, everybody. I will now discuss some of the line items included in Gran Tierra Energy's third quarter 2011 financial results. Revenue and other income for the third quarter of 2011 was $151 million, a 79% increase from 2010 due to increased production and higher realized crude oil prices. The average price received per barrel of oil increased by 36% to $92.76 per barrel for the 3 months ended September 30, 2011, from $68.12 per barrel in the same period in 2010. Increased revenues were partially offset by increased operating costs, depletion, depreciation and accretion and impairment or DD&A and general and administrative, or G&A expenses. Operating expenses for the third quarter of 2011 amounted to $21.7 million, a 12% increase from the same period in 2010. The increase in operating expenses was mainly due to an increase of $5.7 million in operating costs in Argentina, of which, $5.5 million was related to properties acquired from Petrolifera. This was partially offset by a decrease of $3.9 million in operating costs in Colombia due to lower transportation costs as a result of the absence of pipeline disruptions and low workover costs. On a per barrel of oil equivalent basis, operating expenses decreased 17% to $12.86 as a result of increases in production, more than offsetting increased operating costs. Compared to the third quarter of 2010, DD&A increased 41% to $49.9 million, while 4% to $29.50 on a per BOE basis, which included $5.9 million related to properties acquired from Petrolifera and a $7.4 million impairment loss related to the Peru cost center. G&A expenses of $16.3 million for the 3 months ended September 30, 2011 were 49% higher than the same period in 2010 due to increased employee-related costs reflecting expanded operations in all business segments, including…

All right. Thank you, Martin. Gran Tierra Energy is currently undertaking the busiest period drilling in its history with 4 exploration wells to be drilled in Colombia and Brazil and 7 appraisal and development wells to be drilled in Colombia, Brazil and Argentina. In Colombia, the Rumiyaco oil exploration well is drilling ahead, and we expect to reach total depth in November. This high-impact well in the Putumayo basin is testing a structural closure identified by 3D seismic data that is positioned in between 2 producing light oil trends. The Pacayaco-1 sidetrack oil exploration well in the Chaza Block is expected to spud in December and reach total depth before year end. This is a sidetrack to an exploration well drilled early this year that encountered oil shows, but no reservoir. We are now targeting a different location picked after the acquisition and interpretation of a new 3D seismic data earlier this year. The Brillante-2x appraisal well, SE-2x appraisal well, began drilling in October in the Brillante gas discovery in the lower Magdalena basin of Colombia. The intent of this well in Brillante SE-3x, which is scheduled to follow in December, is to define adequate reserves to justify the construction of a gas pipeline and commit to long-term gas sales contract. The well is expected to reach total depth of approximately 6,000 feet this month. A new 275-square-kilometer 3D seismic program has been acquired over the field and will be used for future development drilling, planning and potential exploration drilling around the Brillante discovery. In the Putumayo Basin, we continue to experience success with the Moqueta oil discovery appraisal program. The Moqueta-6 sidetrack was drilled and encountered oil in the Kg sandstone, the U sandstone, the T sandstone, in the Caballos reservoirs. The primary T sandstone in Caballos reservoirs were…

[Operator Instructions] And our first question comes from the line of Matt Portillo from Tutor, Pickering, Holt. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: A couple of quick questions on Moqueta. Could you give us any color around the net pay that you encountered in the well? And then, kind of -- as we think about the ramp up into 2012, how conservative are you planning from a production perspective in terms of ramping up each of the wells that you've had pay in so far? So should we think about, kind of, 500 barrels per well for the 6 wells so far in '12 in terms of production?

We haven't actually physically started producing from Moqueta-6 yet. It's been tied in, test programs just beginning, so I don't have a net pay number to give you from that specific well. The sand thicknesses are consistent with the offset wells and consistent with Costayaco and other wells. So it's, I don't know, 40 to 70 feet of net pay would be an approximation. The typical wells in the basin come on at around 2,000 barrels per day, per well. That is not what we expect to be happening at Moqueta. We need to be managing the reservoir pressures because of the gas cap in the oils saturated with gas, so until we have compression equivalent, either gas or water for the reservoirs, we're going to just, very slowly, grow production. So initially, not on a per well basis but from the field, we don't have a real number to give you, but it'll be a, I'll say 1,000 to 2,000 per day next year, not in the order of magnitude to say Costayaco or other fields where we don't have this pressure -- initial pressure challenges that we have to build facilities for. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just a follow-up on that. When you say the net pay is 40 to 70 feet, is that per targeted horizon?

No, it's for the overall reservoir. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. So you guys found, it looks like, a little bit thinner pay in this well than you had in previous wells.

No, I didn't say that. I said we haven't started testing yet so we have no pay estimates. Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Understood. And then just a second question on the delineation of the Moqueta reservoir. Could you give us an idea, kind of, on timing on Moqueta-7, and additional seismic you'd like to have in place before drilling, if any?

Yes. We don't -- we're preparing to start acquiring a new 3D seismic program. The field work -- or the survey should start this month. Physical acquisition should start next month, December. And so it will be completed in the first quarter, so say the end of first quarter we should have first 3D volume over the entire field. Now in terms of the next Moqueta, the next well, Moqueta-7, we don't have a specific date, it won't be this year, it will be, for sure, second quarter next year -- first half of next year.

Our next question comes from the line of Martin Molyneaux from FirstEnergy Capital Corp.

Gentlemen, just in terms of what incremental data points you're looking for from the Moqueta wells that have been tested so far, in order to paint out the right picture for the optimal development plan.

Basically, Martin, we're looking for the pressure decline and response to either water pressure support finding an eco-column or gas cap expansion from above the oil column. Just basically, we're looking for the rate of pressure support from the gas cap or the water column. And based on that pressure decline and recovery from the testing data, we can then plan the appropriate gas injection volumes or water injection volumes to maintain the reservoir pressure so that the gas does not come out of solution when we produce the wells.

Great. Okay, makes sense. In terms of Brazil, what are you anticipating the timing to be in terms of getting the final approvals from the government to be part of the farm-ins?

I see. For the onshore blocks, we have all those approvals in place. We're up and running. For the 2 offshore blocks, with the StatOil farm-in, it's maybe hopefully by year end, could slip into early next year.

And our next question comes from the line of Nathan Piper from RBC Capital Markets.

If we could step back a wee bit on production and just think of it more broadly. And not just specific to Moqueta, but how do you see your production base evolving next year? So, I guess, first question is, do you think Moqueta can maintain current production -- starting on Moqueta, and Costayaco maintain current production? And what do you think the potential is from some of these discoveries you've been making in Colombia, Argentina, and also where you think Brazil might go? So we can kind of think of your production in the round?

Well, in the big picture, we expect to continue growing production next year, and we don't have any specific guidance yet. We won't have that until, well, December, once we've got our budget for next year approved. But we expect our Moqueta -- this is the base, the Costayaco field may start declining sometime next year, say middle next year. We would expect to -- Moqueta production to at least overcome that decline, if not grow beyond the decline. Then we have these other fields discovered or appraising that will add additional production growth. So, Nate, I don't have a real number to give you, but our plan, our intent, is to continue growing production next year.

Pleased to hear it. On the Brazilian exploration, the offshore well, and you've been kind enough to give us rough end dates for most of the wells apart from that one. Is that because you're not operating or because it's particularly uncertain, or can you give us a little bit of guidance as to when you think that well will -- the result will first come?

[indiscernible] the primary reason is we are not the operator. In fact, we're not actually part of the joint venture yet until the ANP approves the -- our farm-in. So you really have to go to the operator for any updates or operational information.

Okay. And lastly, seeing that you're doing a bit of portfolio management in Peru, could you maybe just give a couple of words on what you think your plans are in Peru? I mean, obviously, in the Petrolifera deal, unsuccessful well at the start of the year, stuff like that. I mean, how should we envision what your plans are in Peru? Where do you see the potential?

Yes. In the near-term, the potential in Peru for us is with reserve additions. We have some very attractive exploration lands, but they're very early in their life cycle in terms of development. But currently we're planning 2 wells, 2 exploration wells next year, and then at least one well the following year on this land. So over the next, say, 2 years, our intent is to discover large, material, large new oil reserves. Then again with Peru, not being as mature in terms of infrastructure and timing of permitting and such, we wouldn't expect production from these fields to begin until, say, 2 to 3 years after that. So for us, for Gran Tierra, Peru is all about near-term reserve growth potential in the coming 2 years versus, say, Colombia or Brazil where we can see the potential to actually grow production and reserves in the near-term.

Okay. If you may, let me one final question to be topical. Perhaps talking very broadly, very positively about the Neuquen Basin, you have got some increase there with -- that you mentioned already. I mean, do you see anywhere near the same unconventional potential where you are, or is yours simply a relatively modest, conventional opportunity?

In Neuquen Basin, we're on the plank of the basin, so the source rocks are not mature, so I'd say there's modest unconventional potential on our Neuquen acreage. Now in the North, in the Santa Victoria Block, we do have significant unconventional potential, as well as conventional potential, and that's what we hope to be evaluating next year with one well.

And our next question comes from the line of George Toriola from UBS.

The question is around Costayaco, could you -- just to be able to get a bit of an insight into the production profile going forward here. Are you able to talk about voidage replacement and some of the metrics you're seeing with regard to your waterflood -- or water injection, I mean?

Yes. We are -- we just completed another water injector, Costayaco-15. And that's injecting water both in the T and the Caballos. With our previous water injectors, we've been very successful. And now with this well, this is also proving up to be very successful. So I'd say we're -- we've got the -- we're either at now or have the potential around 10,000 barrels a day of water injection. So that doesn't match our voidage, but we're seeing very good pressure response or recovery from this injection. We plan to continue growing our water injection. And plus, this water injection is being supported additionally by the aquavoir pressure underlying the oil column, so we don't actually need to be matching voidage with our water injection program. So I'm not sure that answers your questions, but we are successfully replacing a significant portion of our voidage, with the balance being from the water column.

That's helpful. But in terms of, when you look at the T and the Caballos, where is the great opportunity from a water injection standpoint?

In the near-term, it's in the Caballos. To date, the vast majority of our injection has been in the T sand with little, if any -- actually perhaps no injection in the Caballos. So Costayaco-15 is the first water injection in the Caballos. That's where the immediate benefit will be coming from.

Okay. And so as you've said before, the plateau here should still be probably extending a year out or something like that.

Well into next year. And then we'll just have to see how it plays out with additional data from the new water injection well we just completed.

And our next question comes from the line of Charles Carvalhal from JPMorgan. Caio M. Carvalhal - JP Morgan Chase & Co, Research Division: Well, I had an initial question trying to just get a little bit color on the production volume from next year, but I understand subject this is subject to the budget approval so I'll skip that one. I have 3 kind of specific questions, one on Brazil, Peru and Argentina, sorry Brazil, Peru and Colombia. First of all, my Brazil question. I understand that you need to have an approval from ANP before being, sort of, officially part of the consortium. My question would be, the announcement of any guidances on potential volume of potential risk of assets we are exposed is only subject to the officially approved from ANP or, actually, I mean, Gran Tierra, according to the JOA you have with Statoil, any announcement should have come from Statoil. And the other question on the Brazil is that, is that possible to you at least tell us what did the final depth of the well in this target?

We're not allowed to say anything about the acreage or details on the well. That can only come from the operator. Caio M. Carvalhal - JP Morgan Chase & Co, Research Division: I know. Okay. Okay, perfect, I'm used to that. I just wanted to check it. On Argentina, the question is, on this potential developments you have in Argentina, do you believe any of them could be sort of scripted in the oil clause agreement, meaning that you would be able to get a, sort of, a larger net back from the oil, or everything that you have in Argentina it's already given that you be capped with roughly about $58 per barrel cap in Argentina?

No, we -- that's actually a good question. No, we sell all our crudes domestically, so none of our crude is exported, so we are not strictly capped. In fact, every year now -- well, almost 3 years now, our oil prices have been rising consistently month-over-month. And in fact, our most recent oil sales are for around $68 per barrel in the Neuquen Basin, a couple of dollars less in the Noroeste Basin in North. So what we have seen and we're seeing today as we speak is continuously rising oil prices in the domestic market. Caio M. Carvalhal - JP Morgan Chase & Co, Research Division: Okay. I agree that's the trend in the -- okay, fine. And my last question is on Peru. It's actually 2 questions, one on Marañon , and the other one on Ukalali. On Marañon Basin, do you have an idea when can we expect some production from Peru? I assume likelihood is on Marañoz today. And the second question, on the elephant hunting in the Blocks 133 and 107. You mentioned that we are expecting -- we are, I mean, awaiting for the license to begin drilling operations. Do we have any -- do you know more or less when should we expect, I mean, I assume you guys have filled some requests to the environmental agency there. My question is, when can we expect this license to be delivered, if you have an expectation? And if the change in Peruvian administration should have any impact on the environmental license for this region?

Okay. In terms of the change in administration, the environmental permits, or the permit process in general in Peru are very, very slow. And with the new administration, they said they will try to improve the efficiency and accelerate the permit process cycle time. So initial statements and intent of the new administration is positive from the perspective of the oil sector in reducing the cycle time abated by the current permit process. So that's good. Now for Block 107, we expect to drill the first well there in late next year. Our current plan is to use the same rig as we drill on Block 95, which we expect to drill in the middle of next year. Now the permits are in place or in progress. On Block 195, the key government approval we're still waiting for is the approval of our farm-in there. We are still not officially a partner in that block. The farm-out agreement has been signed, but we're still waiting for the government approval of that farm-in similar to what we are doing in Brazil, waiting for the regulator approval there. So the environmental permits are, for most part, in place for the drilling on one block, Block 95, we're still waiting for the government approval of the farm-in. Caio M. Carvalhal - JP Morgan Chase & Co, Research Division: Okay. And about production in Peru, do you have...

Yes. In production, let's say if we make the discovery or -- in the Marañon next year, we would expect first production in 3 to 5 years, in that timeframe. Caio M. Carvalhal - JP Morgan Chase & Co, Research Division: Okay. 3 to 5 years for new discovery, but what about the Britannia region? I understood you would be delineating that in the first half of 2012.

We'll be drilling well in the middle of 2012. Our intent is to do a test, like a drill-stem test. If successful, we would like to do a long-term test. To do a long-term test, it will require barges to transport the crude from Brittania to the existing pipeline system. And then conservatively, we're going to say it's going to take 3 years to get those permits. We may be able to do that faster, but until we've seen evidence of the permitting system actually accelerating, we'll say 3 years.

And our next question comes from the line of David Dudlyke from Stifel Nicolaus. David Dudlyke - Stifel, Nicolaus & Co., Inc., Research Division: If I may continue with the conversation regarding Peru. You spoke earlier about the relinquishment by yourselves and your partners of the 3 blocks. I guess my first question is, are there any costs tied to the recent rescindment of those blocks? And secondly, given what I understood to be the relatively modest cost of drilling the wells, what did you learn from that first well on your own block, that in terms of the various risks, that are company exploration? And what does that mean in terms of your own view of de-risking of the blocks that you retained, 123 and 129, along with Conoco, was it migration, was it the reservoir, what went wrong on that original well?

Yes. Well, we fulfilled all of the obligations on our acreage that we've relinquished, so there was no additional cost there. What we found with our well was the reservoir was present, and the top seal was present, but it did not address the critical risk, which was did oil migrate that far? We found no evidence of migration, so the critical risk is still unresolved. Now the ConocoPhillips acreage is closer to the kitchen. It's immediately adjacent to precinct oil fields just to the west. So that risk is not as high as on our original 2 blocks because they're closer to the kitchen. David Dudlyke - Stifel, Nicolaus & Co., Inc., Research Division: Understood. And given the geographical situation of those 3 blocks, 129, 123 and 124, that you hold with Conoco, from which direction does the migration -- you've obviously chosen to drop 124, so do I conclude that the kitchen is to the north and west, such that 29 and 23 still make it?

It's really northwest, west and southwest -- to the southwest is where the Block 95 is in that Brittania field. You really have migration potential from the entire western flank of the arch or the eastern flank of the basin. David Dudlyke - Stifel, Nicolaus & Co., Inc., Research Division: Okay. Perhaps you can tell me, what are yours and Conoco's plans on those 2 blocks, 29 and 23? Obviously, I understand your near-term plans regarding Block 95, in particular, but what do you and Conoco have planned for 123 and 129 and when?

We continue the 2D seismic program. We have -- well, we're going to shoot an infield 2D seismic program on most prospective portions of the blocks. And then based on those results, we'll make the decision after that what to do next. We won't be -- well, I'll say it's extremely unlikely we'll be drilling next year. There's potential for drilling the year after next. But the joint venture has made no plans and I can't really speak to any details on the block. David Dudlyke - Stifel, Nicolaus & Co., Inc., Research Division: Fair enough. Switching to offshore Brazil. I understand that, as you said with regard to earlier questions, that Statoil, as the operator, should address the subsurface. But can you at least confirm the farm-in, or at least, confirm my understanding that essentially you are carrying Statoil's 60% and, perspectively, their 40% of the first exploration well on each block? So essentially, you're carrying the cost of one offshore deepwater well as your...

I can't disclose the specifics of the farm-in agreement. That's confidential. But we are promoted on the first substration well. So we're not carrying Statoil, but we're carrying a portion of their costs. But I can't get into the details. David Dudlyke - Stifel, Nicolaus & Co., Inc., Research Division: I guess the other way of reversing into it. Yes, I think you've said that you expect some $17 million of capital expenditure in 2011 to be allied to this ongoing well. Is that the total cost? Or do we expect some residual to flow through into 2012, and, if so, how material is it relative to that $17 million?

It's not material. And I would not expect additional costs next year with the farm-in. David Dudlyke - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then, again, switching gears back to Argentina. I heard you state earlier that you didn't believe that you had much unconventional plays within your Neuquen acreage. But with regard to that recent success on Rinconada Norte, do you plan to elevate your drilling plans on your operated acreage to the southeast of Vaka Macuda?

Well, I'll say we're studying that opportunity. We haven't made a final decision, but I guess the short answer is, yes, we are looking at pursuing that further.

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

I think my questions are all for Martin, if he's still here. Just trying to understand how to forecast your tax rate again. I think it's a question that's come up a couple of times in previous quarters. Looking at the tax items disclosure in your Note 8, there's a lot of, kind of, items that I consider relatively difficult to forecast, such as the increase in valuation allowance, the other permanent differences. And I was wondering if you could kind of talk through each of those items, as well as maybe the nondeductible third-party royalty, explain what they are, and how we might be able to forecast them, to get an idea on what your Q4 cash tax and total tax rate might be, as well as some guidance for 2012?

Okay. So I think the important thing to remember is Gran Tierra is a fairly complex company. We're operating in 4 countries in South America, plus you have expenditures in Canada and the U.S. But the only place we actually pay any cash taxes is in Colombia. So you have to determine what our Colombian taxable income is, and then we apply 33% tax rate to that. One thing to note is that in 2010, we have a 30% -- we had a 30% special deduction on eligible capital expenditures. That program in Colombia ceased at the end of 2010, but we have applied for an extension, like a 3-year extension, we submitted an application along with a number of other companies. That application is still under review. So pending that, we have not taken any benefit of that additional tax deduction. So essentially, when you're forecasting, I think you just have to look at Colombia and figure out what our Colombian taxable income and apply the Colombian tax rate of 33%. The rest of the items, like valuation allowance is essentially any expenditures in North America or in Peru or any of the other jurisdictions we basically take a valuation allowance against because we cannot have any certainty that we're going to recover those expenditures for tax purposes. I'm actually, jumping around a bit here, I'm not looking at the note, but unrealized foreign exchange gains or losses, they're not taxable, so they got adjusted in the calculation. The gain on acquisition of Petrolifera, that's a nontaxable item.

Is this answering your question, Jamie?

Yes, it is. Just the nondeductible third-party royalty, can you say what that is?

Yes. We have a net profits interest in our Colombia operations. That is payable in the U.S. and it's, therefore, it's not deductible for Colombian income tax purposes.

So and it only started to become payable in Q4 2010 when you reached the threshold, that way it only started to appear in your financials in Q4 2010?

It became more significant then.

I think that answers the question, and I'll follow up afterwards if we need anything more.

And we have a question from the line of Neal Dingmann from SunTrust.

This is Joanna for Neal. We had some technical issues, I'm sorry, if you have covered this earlier. But in terms of the political activity in Argentina and repatriation regulation, can you tell us how that affects your operations or your plans for spending in the area?

Yes. There was one news item a few weeks ago where there's a change in -- or people exporting crude out of the country which they had to repatriate or keep all their funds in country. That change in regulation had no impact on Gran Tierra because we are not a crude oil exporter. So no impact on us, it's just business as normal, and we're continuing to reinvest our funds in Argentina in our Argentine operations. And the then other comment, which I mentioned earlier, is we are actually seeing month-over-month rising oil prices in country.

Okay. Great. And just one more. For the Moqueta deal, can you just talk -- have your total expectations for the field as a whole, have those changed at all? Or -- yes, can you give us more color on your expectations or the potential there?

Yes. I can't give you a specific number because we don't have the number, but yes, our expectations have changed with our recent drilling, the field appears to continue -- or it is continuing to get bigger. So the reserves in the field are getting bigger. We don't have a full field development plan yet. We probably won't have that till maybe second quarter next year. But the new data suggest the field is getting bigger.

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

All right. Well, thank you, Francine. And once again, I'd like to thank everyone for joining us today. We look forward to speaking with you next quarter to update you on our progress. Thank you, everyone. Goodbye.

Ladies and gentlemen, we thank you for your participation in today's conference. You may now disconnect. Have a great day.