Gran Tierra Energy Inc.
Q2 2014 Earnings Call Transcript

Published: 8 Aug 2014

[Operator:]

Good afternoon, ladies and gentlemen, and welcome to Gran Tierra Energy's Results Conference Call for the Quarter ended June 30, 2014. My name is Katina, and I'll be your coordinator for today. [Operator Instructions] I would like to remind everyone this conference is being webcast and recorded today, Thursday, August 7, 2014, at 4

[Dana Coffield:]

Thank you, Katina. Good afternoon, and thank you for joining us for Gran Tierra Energy's Second Quarter 2014 Results Conference Call. With me today is Shane O'Leary, our Chief Operating Officer; and James Rozon, our Chief Financial Officer. Yesterday evening, we disseminated a press release that included detailed financial information about the quarter. In addition, Gran Tierra Energy's 2014 report on Form 10-Q for the 3 months ended June 30, 2014 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 and Shane will then take a few minutes to provide an operations update. I will then return to provide a budget update and closing remarks. Gran Tierra Energy has continued to successfully execute a strategy, focusing on its core assets and operating capability, while continuing to position for an exciting exploration and development program in the second half of 2014. Our Argentina business unit was successfully divested, while we continued development of our Costayaco and Moqueta fields in Colombia, which in turn continue to deliver a strong production and cash flow. Preparations for continued drilling of 4 exploration wells in the Putumayo Basin in Colombia in the second half of 2014 and one important development well in the Bretaña field in Peru, which is expected to shift a large amount of the possible reserves into the probable category. Finally, and very importantly, we continued planning to initiate our first crude oil production in sales from that field before year end. Let me talk a little about the quarterly results. Production from continuing operations for the second quarter of 2014 averaged 26,261 barrels of oil equivalent per day working interest or 19,857 barrels of oil equivalent per day net after royalty before adjustments for inventory changes and losses, or 17,524 barrels of oil equivalent per day net after royalty adjusted for inventory changes and losses. 99% of this production was oil. Gran Tierra Energy expects a sale of the large inventory build from the second quarter during the third quarter of 2014, before inventory adjustments production in July of 2014, average approximately 19,000 barrels of oil equivalent per day net after royalty. As a result of the Argentina business unit sale, we have revised 2014 average production to range between 19,500 and 20,500 barrels of oil equivalent per day net after royalty before adjustment for inventory changes. This figure excludes production from Argentina for the full year 2014, and approximately 99% of this production will consist of oil and the balance, natural gas. Funds flow from operations was $85 million for the second quarter compared to $87 million in the first quarter of 2014. Our balance sheet remains strong with cash and cash equivalents totaling $332 million at the end of the quarter. We remain debt-free. Shane will go through the operational results for the quarter shortly, but highlights include, in Brazil, adding considerable reserves as a result of additional technical work in the Tiê field. Using SEC reserve reporting guidelines, this has resulted in 1P reserves increasing 80% to 3.5 million barrels of oil, 2P reserves increasing 48% to 5.6 million barrels of oil and 3P reserves increasing 44% to 8.2 million barrels of oil on a company interest basis. The net present value of the 2P reserves has increased $267 million at May 31, 2014 from $115 million at December 31, 2013. In Colombia, the Moqueta-13 development well was successfully drilled, tested at approximately 1,500 barrels of oil per day and tied in. Similarly, the cost of Costayaco-21 development well was successfully drilled, tested and tied in. Production both are expected this -- production from both are expected to start in the third quarter of 2014. Exploration drilling plans in Colombia for the remainder of the year were finalized, with wells to include the Eslabón Sur Shallow-1, Eslabón Sur Deep-1, Corunta-1A and the Cabañas-1, all in the Putumayo Basin. And finally, Peru planning continued for the initiation of our first crude oil production sales from the Bretaña field in the fourth quarter and for the drilling of an appraisal well in the field that should have substantial impact on reserves, if successful. So let me now turn the call over to James Rozon to discuss the financial results in more detail. James?

[James Rozon:]

Thank you, Dana. 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. On June 25, 2014, we sold our Argentina business unit to Madalena Energy for consideration of $69 million comprising $55 million in cash and $14 million in Madalena shares. The results of the Argentina business unit, together with the loss on sale, are presented as loss from discontinued operations, net of income taxes, in the company's interim unaudited condensed consolidated statements of operations. Revenue and other income and expenses include results from continuing operations and exclude the results of the Argentina business unit. For the second quarter of 2014, revenue and other income decreased by 2% to $149 million from $152 million compared with the first quarter of 2014 due to lower production, resulting from increased inventory in Colombia, partially offset by higher realized prices. Average realized oil prices increased by 4% to $93.72 per barrel for the second quarter of 2014, compared with $89.89 per barrel in the first quarter of 2014 due to lower volumes sold in the current quarter for which price is adjusted for trucking costs. Revenue and other income in the second quarter of 2014 decreased by 1% to $149 million, compared with $151 million in the corresponding quarter in 2013 as a result of decreased production due to increased oil inventory, partially offset by increased realized prices. An inventory increase accounted for 2,320 barrels of oil per day of reduced production compared with an inventory increase of 205 barrels of oil per day in the comparative quarter. The average price received per barrel of oil increased by 8% to $93.72 for the second quarter of 2014 from $86.71 in the second quarter of 2013 due to a higher Brent oil price and a lower percentage of volumes sold in the current quarter for which the price is adjusted for trucking costs. During the second quarter of 2014, 39% of our oil and gas volumes sold in Colombia were to a customer where the realized price is adjusted for trucking costs related to a 1,500-kilometer route. The effect on the Colombian realized price for the second quarter of 2014 was a reduction of approximately $6.94 per barrel to $93.56 per barrel as compared to delivering all of our Colombian oil through the OTA pipeline. Sales to this customer during this corresponding quarter in 2013 were 51% of our oil and gas volumes sold in Colombia and the effects on the Colombian realized price was a reduction of approximately $11.30 per barrel. Operating expenses in the second quarter of 2014 increased by 6% to $25 million from $24 million in the comparable quarter in 2013. For the second quarter of 2014, the increase in operating expenses was due to an increase in the operating cost per BOE, partially offset by lower production. On a per BOE basis, operating expenses increased by 15% to $15.89 in the second quarter of 2014 from $13.82 in the corresponding quarter in 2013, primarily as a result of higher pipeline charges and trucking costs due to a higher portion of our sales through the OTA pipeline in 2014. The estimated effect of OTA pipeline disruptions on Colombian transportation costs for the second quarter of 2014 was a savings of $1.33 per BOE as compared to -- or compared with delivering all of our Colombian oil through the OTA pipeline. In the corresponding quarter in 2013, the net savings was $2.20 per BOE. Operating expenses increased by 16% or $3 million from the $22 million in the first quarter of 2014 due to higher workover, maintenance and health, safety and environmental expenses in Colombia, partially offset by the effect of lower production. Depletion, depreciation, accretion and impairment or DD&A expenses in the second quarter of 2014 were $42 million compared with $56 million in the corresponding quarter in 2013, primarily due to lower production and a lower depletion rate. On a per BOE basis, the depletion rate decreased by 18% to $26.30 from $32.06. On a per BOE basis, the decrease was are primarily due to an increase in reserves and a decrease in cost in a depletable base relating to lower future development costs and the receipt of a termination payment in Brazil in the third quarter of 2013, which reduced the cost base. General and administrative, or G&A expenses, for the second quarter of 2014 increased by 53% to $14 million compared with the corresponding quarter in 2013. Increased employee-related costs, higher consulting expenses associated with increased activity, expanded operations in Peru and higher bank fees were partially offset by higher G&A allocations to capital projects within the business units during the second quarter of 2014. G&A expenses per BOE in the second quarter of 2014 of $8.74 were 67% higher compared with the $5.24 in the comparable quarter in 2013, due to lower production and increased costs. In the second quarter of 2014, the foreign exchange loss was a $10 million, comprising a $9 million unrealized noncash foreign exchange loss and realized foreign exchange losses of $1 million. The unrealized foreign exchange loss was a result of a net monetary liability position in Colombia, combined with strengthening of the Colombian peso. For the second quarter of 2013, there was a foreign exchange gain of $13 million, comprising a $12 million unrealized noncash foreign exchange gain and realized foreign exchange gain of $1 million. Financial instruments gain of $3 million in the second quarter of 2014 was primarily related to gains on our nondeliverable forward contracts. We had income from continuing operations in the second quarter of 2014 of $31 million, compared to $50 million in the comparable quarter in 2013. In 2014, decreased oil and natural gas sales, higher operating G&A and income tax expenses and foreign exchange losses were partially offset by lower depletion, depreciation and accretion expenses and financial instrument gains. Loss from discontinuing operations, net of income taxes, was $22 million for the second quarter of 2014 compared to $2 million in the corresponding period in 2013. In 2014, loss from discontinued operations, net of tax, included loss on disposal of the Argentina business unit of $19 million. Net income for the quarter of $9 million was $36 million lower than the net income of $45 million in the first quarter of 2014. Net income for the quarter also decreased compared with $48 million in the comparable period in 2013. The decrease was due to lower income from continuing operations and higher loss from discontinued operations, net of income taxes. Funds flow from continuous operations was $85 million, a decrease of 2% or $2 million from $87 million in the first quarter of 2014, and a decrease from $86 million in the comparable quarter in 2013. The decrease was primarily due to the effect of inventory adjustments. Cash and cash equivalents were $332 million at June 30, 2014 compared with $429 million at December 31, 2013. The decrease in cash and cash equivalents during 2014 was primarily the result of cash capital expenditures of $158 million, cash used in investing activities of discontinued operations of $12 million, a $143 million change in assets and liabilities from operating activities and cash used in operating activities of discontinued operations of $5 million, partially offset by funds flow from continuing operations of $172 million, net proceeds from the sale of the Argentina business unit of $43 million and proceeds from the issuance of shares of common stock of $7 million. In summary, we remain financially strong. We continue to expect that our 2014 capital program of $482 million will be funded from cash flow from operations and cash on hand. That concludes my comments. I would now like to turn the call to Shane for an operations overview and update for the remainder of 2014.

[Shane P. O'Leary:]

Thank you, James. Gran Tierra Energy had another successful quarter in executing its operations. On the Chaza Block in Colombia, the development of the Costayaco field is ongoing with the Costayaco 20 and 22 wells both spud in the first quarter of 2014 and put on production in the second quarter of 2014 to help maintain plateau production in the field. Production from both wells is approximately 2,700 barrels per day. Costayaco-21 has been drilled, tested and tied in with production start-up imminent. The Costayaco-19 development well is drilling ahead. Development of the Moqueta field continues with the Moqueta-13 development well drilled in the southeast direction from the Moqueta-1 well pad. The well encountered oil in the T-Sandstone and Caballos formations which, together, tested approximately 1,500 barrels of oil per day on a restricted choke. The well has been tied in and is currently producing about 1,250 barrels per day from the T-sand only. Drilling of the Moqueta-14 has just begun with drilling expected to take approximately 1 month. Subsequent to the end of the second quarter of 2014, we were the successful bidder on Putumayo-31 block in the Putumayo Basin of Colombia and Colombia's National Hydrocarbon Agency 2014 bid round. And we are expected to become the operator of the block subject to final government approval. Our planned work program for the remainder of 2014 in Colombia includes drilling the Eslabón Sur Shallow-1 and Eslabón Sur Deep-1 exploration wells, which are targeting the same Cretaceous Sandstones encountered in the Costayaco and Moqueta fields. These wells are expected to begin drilling in the third and fourth quarters of 2014 respectively. The Corunta-1A exploration well is expected to spud in the third quarter of 2014, and will be drilled in a northeast direction from the Costayaco-17 well pad, targeting a downthrown fault block west of the Moqueta field. Finally, the Cabañas-1 exploration well is expected to be drilled in the fourth quarter of 2014 in the Putumayo-1 Block. This block is immediately south of the Chaza Block in the Putumayo Basin where we have encountered multiple exploration successes. The Cabañas-1 well is targeting the same Cretaceous Sandstones encountered in the Costayaco and the Moqueta fields. On Block 95 in Peru, The Bretaña 1 water disposal well was drilled and completed close to budget and on schedule. Of note, is that this well tested oil from an oil-water transition zone at the base of the oil column in which no reserves have been booked to date. Planning and construction is underway to initiate drilling of the Bretaña Sur delineation well in the fourth quarter of 2014, to gather additional reservoir data and further substantiate oil reserves in the field. We plan to initiate the long-term test production from the Bretaña discovery in the fourth quarter of 2014, and expect a rate of approximately 2,500 barrels of oil per day gross. The long-term test will provide valuable information on the reservoir to optimize field development, in addition to providing early cash flow. Currently, we have a 6-month test period with the option to extend it another 6 months, and we plan to explore options of extending testing beyond the 1-year time period. In Brazil, after dual completions of the GTE 3 and 4 wells in the Tiê field, seismic reprocessing and the addition of a previously unrecognized reservoir volume in the Sergi formation, reserves have been reassessed by our reserve auditor, GLJ. Using SEC reserve reporting guidelines, this has resulted in a 1P reserve increase of 80% to 3.5 million barrels, 2P reserves increasing 48% to 5.6 million barrels, and 3P reserves increasing 44% to 8.2 million barrels on a company interest basis, and 1P reserves increasing 3 million barrels, 2P reserves increasing 4.9 million barrels and 3P reserves increasing to 7.2 million barrels on a net after royalty basis. The net present value, NPV10 before tax, of 2P reserves has increased to $167 million at May 31, 2014 from $115 million at December 31, 2013. For the remainder of 2014 in Brazil, our focus will be to continue to evaluate the conventional and unconventional resource opportunities in oil saturated tight sands and shales in Recôncavo Basin. The work program will include 120-kilometer 3D seismic program on Blocks 86, 117 and 118 starting in the fourth quarter. We are also evaluating options to tie in gas production from the Tiê field to existing infrastructure, which has the potential to more than double oil production due to gas flare restrictions. I'll now turn it back over to Dana for concluding comments.

[Dana Coffield:]

Thank you, Shane. So Gran Tierra Energy's planned capital program for exploration and production operations in Colombia, Brazil, Peru and Argentina for 2014 has been revised to $482 million from $495 million. This now includes $249 million for Colombia, $37 million for Brazil, $18 million for Argentina, $173 million for Peru and $5 million associated with corporate activities. Much of the second half capital program spending will be allocated to drilling the 4 exploration wells in Colombia, 3 of which are on the same block as Costayaco and Moqueta fields. On the Bretaña discovery in Peru, we continue to work on facilities and continue to plan for the first production in the fourth quarter, and we are making substantial progress and have just signed a large transportation contract for transporting our crude to a refinery in the city of Aquitos. In the second half of this year, Gran Tierra Energy is poised for additional production growth, with plans to reach 30,000 barrels of oil equivalent per day gross working interest or 23,000 barrels of oil equivalent per day net after royalty before adjustments for inventory changes and losses before year end. And believes this drilling, development drilling, in Bretaña may lead to significant increase in 2P reserves if successful. In addition, exploration success in the Putumayo basin may add additional reserves in the production to our base. On a personal note, as Shane prepares for retirement, I would like to thank him for his incredible contributions to the growth of Gran Tierra Energy over the last 6 years, helping the company manage its remarkable growth and building a team of high performance explorers and developers of crude oil in South America that will continue building this company. Similarly, I look forward to Duncan Nightingale returning to Calgary from Bogotá to fill Shane's role, bringing with him his 5 years of on-the-ground experience in Colombia to share with our growing company. That concludes our prepared remarks for this afternoon. We would now be pleased to answer any questions you might have. Katina?

[Operator:]

[Operator Instructions] Your first question comes from the line of Nathan Piper representing RBC.

[Nathan Piper:]

A few questions for me, if I may. First of all, on Peru, can you just remind us of where we're at and where we might be going in delineating the size of the Bretaña field? So can you confirm the recovery factors that were applied by your reserves auditor to come up with the 60 million and 114 million barrels you've got so far? And then, secondly, what is Bretaña Sur targeting and what's the scale perhaps of the add that it could see if it's successful? And then, maybe lastly, if you get to [ph] include the Envidia lobe that you guys spotted in the seismic on a conservative basis, what kind of scale structure are we looking at in the round?

[Dana Coffield:]

Nathan, this is Dana. I don't recall the recovery factors in the report. I don't know if they're actually in the report. The range -- there is range -- sorry, of recovery factors for each of the reserve categories. It will range from 10% to 20%, but I can't recall specifically those numbers. In terms of the Envidia's size, in terms of the scale of additional potential there, just based on area from the map area, there could be another 10% to 20% of resource additions there. And then, I think the other question was the amount of reserves that could go from the 3P into the 2P category. It could be very substantial at least 50%, another 30 million barrel order of magnitude. But again that will be up to the results of the well and GLJ to determine.

[Nathan Piper:]

Of course. I guess what I meant was if you have a long-term production test alongside the Bretaña Sur well, I guess that provides further evidence on recovery factor and I guess the point is it's relatively conservative recovery factor that's being applied at the moment.

[Dana Coffield:]

That's correct. And in fact, you've hit it straight on the nose is GLJ, as well as Gran Tierra needs to see the results of the long-term test to get a better feel of what the recovery factors will actually be. And similar to what happened in Costayaco, early assumptions were very conservative. With production history, we're able to increase those recovery factors based on production data. So you're correct. The initial assumptions will be on the conservative side.

[Shane P. O'Leary:]

17% [indiscernible].

[Nathan Piper:]

Understood. I have a follow-on question please [indiscernible] topic. Just to confirm, in terms of the activities in the second half, have you got all the rigs; have you got all the approvals; are all the drill pads ready? Or put in another way, is there anything that -- well, there's always something that can happen, but have you everything in place in order to achieve all the different bits of drilling [ph] that you've talked about both in Colombia?

[Shane P. O'Leary:]

In Colombia or Peru?

[Nathan Piper:]

Either and both.

[Shane P. O'Leary:]

In Peru, there is 1 or 2 permits that are still outstanding for the L4 location well, the Bretaña Sur well, and -- but we fully expect those to be in place to enable us to drill that well in the fourth quarter. In Colombia, I believe that we have all of our permits in place for the, certainly, for the Moqueta wells, Costayaco wells. The exploration wells, the answer is yes.

[Nathan Piper:]

And likewise, the rigs and everything else, you got that secured or on the way or...

[Shane P. O'Leary:]

Well, in the case of Peru, we actually have the rig on our platform. We're paying a -- what we negotiated was a very low standby rate with the rig company, it's in everybody's best interests just to keep it in the vicinity because we know we're going to be drilling that well in the fourth quarter. So we definitely have that rig. We'll have 4 rigs going in Colombia and 3 of them are currently doing work for us, and I have not heard any issues related to securing the fourth rig. So I don't see that being a problem.

[Operator:]

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

[Pedro Medeiros:]

Well, I have a couple of questions as well. The first one is related to Peru. Do you mind sharing what was exactly the CapEx you drew [ph] and completed Bretaña, the water disposal well? And you mentioned at budget, but I wonder how does that compare to the exploration well and to the cost per well you were forecasting for the actual development plan for Bretaña.

[Shane P. O'Leary:]

Yes, the well -- well, the well was actually cheaper than the first well because -- well, first of all, we didn't do a lateral off of it, we just drilled a vertical well. The design was a lot simpler. The completion is a lot simpler because we're actually just looking at injecting water. So it wasn't as much involved in completing the well. I'm trying to remember the -- I think the cost of the well was roughly $30 million.

[Pedro Medeiros:]

$30 million. And is there any major difference you drilling the water disposal well to the effective production wells?

[Shane P. O'Leary:]

Well...

[Dana Coffield:]

The production well is going to be drilled much differently. The water injection well was a vertical wellbore and the producing wells that we're planning will be deviated wells going off in different directions that will then go horizontally through the reservoir section. And then, each of those will have a sidetrack or some of them, in some cases, maybe 2 sidetracks. So we'll have duolaterals or trilateral wellbores in the reservoir. So the production wells that we're planning are much more complicated wells than a simple water disposal well.

[Pedro Medeiros:]

Okay. And as far as Bretaña goes as well, I understand the that current schematic for developing the whole P2 and even the P3 reserves already both for Bretaña would involve only the deployment of 3 platforms. Can you share a little bit of how you think of the timeframe for deploying these platforms? And when you expect to start contracting those? Is it -- do you need to complete the extended well pads for the 6 months? Or is there any chance you could go to the market before that?

[Dana Coffield:]

Yes. Well, the first platform, of course, is already built. And we'll be focusing the development drilling on that northern platform in the first few years. We are building the second -- or about to start building the second location for the L4 well. So it will be built by the end of the year, of course. It's not clear yet when we'll expand that well -- or that area, that platform because we won't be doing a development drilling there for probably 2 years. And then the third platform or a fourth, if required, will be a couple of years beyond that. So really, the platform construction you're referring to is going to be staged over 4 to 5 years, with no sort of [ph] drilling activity taking place in the first few years on the existing platform.

[Pedro Medeiros:]

Okay. Perfect. And just one last question related to Peru. Do you have any updated timeframe for drilling the prospects on the other licenses different than Bretaña?

[Dana Coffield:]

We're planning on 3 exploration wells in the coming 2 years. So the first of those will be drilled in second half of next year on Block 107. And then, in the second half of the following year, 2016, we'll be drilling on our 2 northern Blocks 123 and 125.

[James Rozon:]

29.

[Dana Coffield:]

29. Sorry, 29.

[Pedro Medeiros:]

Okay. Perfect. And my last question is related to Brazil. Can you comment on further reserves upside through the conventional reservoirs either from Agua Grande and Sergi following the same type of upgrades that you just had that you're finding to touch [ph] anything new in the next 6 to 12 months that could upgrade the reserves from Brazil further?

[Dana Coffield:]

There's potential for modest reserve upgrade with additional production history. There's also potential for additional reserve upgrade with additional development drilling. Probably 1, maybe 2 more wells, development wells, could add additional reserves. We may see those get drilled next year. And so I guess the short answer is yes, there is additional reserve potential in the existing Tiê field. In closer near term, the real upside is not just the reserves, but the potential to significantly increase production. If we can come up with a solution for the gas instead of flaring it, actually, transport the gas or sell the gas, we could then effectively double our current production in the field. So there is both reserve upside potential, as well as production growth potential.

[Operator:]

Your next question comes from the line of Brant Marquardt [ph] representing Amber Capital.

[Unknown Analyst:]

Just on Bretaña again. There is a Bloomberg article at the beginning of June, which stated you guys were looking to possibly accelerate development here. I was just wondering if this is still being contemplated. And if so, what's required for this decision to go ahead?

[Dana Coffield:]

We're doing a -- well, we're just now starting a feed study from an engineering design study that will mature our existing pre-feed study. So in the pre-feed study, we talked about 7,000 barrels a day in 2017, somewhere between 20,000 and 40,000 barrels a day around 2021. So this feed study is going to provide more detailed resolution to our plans. And within those plans -- again, it's just starting. There is a potential to bring that production profile forward. But we won't know definitely what that plan will be until the, well, I'll say, the first quarter of next year. So yes, there is a potential, and we're working that different drilling options to try to realize that potential to bring production forward. One aspect we're working on is drilling a -- what we're calling a test well, a duolateral well in the second half of next year, which will explore the northern end of the Bretaña field. And with 2 laterals, if successful, with that exploration, then we could again contribute to bringing that production forward. But right now, it's very early days and we can't speak definitively to what the outcome would be.

[Unknown Analyst:]

Okay. And just on the rig you have in place, would you expect -- I guess, would it be fair to assume that you'll get keep that busy? Or would you give that up in 2015?

[Dana Coffield:]

We'll probably -- depending on the...

[Shane P. O'Leary:]

We'll re-tender [ph]. We're keeping it for the L4 well, and it will be included in the tender process for the main field development and any additional drilling that we do.

[Operator:]

Your next question comes from the line of Caio Carvalhal representing JPMorgan.

[Caio M. Carvalhal:]

I had a couple of questions in Peru and one specifically in Colombia. But I'll start with Colombia because in Peru, most of it has already been addressed. When I look at the number of days that you had the pipeline interrupted, it seems to me that in the second quarter of 2014, you didn't have a particularly high number of days interrupted. It was actually slightly lower than, I guess, last quarter and lower than what we saw over the same period last year in 2013. However, it seems to -- it also seems to me that for some reason, the prediction was much strongly affected this quarter than before. So I'd like to try to understand what happened. Why '13 volumes were lower than, let's say, expected? So what is the difference? And also, is this related to the cut in the guidance? Because I mean, part of the cut in the guidance is clearly related in Argentina, but it seems that the guide -- the cut is actually higher than what Argentina was contributing. So I guess, it's also related to lower expectations in Colombia. So again, I would like to understand what happened differently in the above ground conditions, and if we are actually experiencing some change in the geological expectation in Colombia as well.

[Dana Coffield:]

Yes, the big event in the second quarter with transportation is the fact that the OTA pipeline was actually down for a significant portion of the quarter due to a landslide. So there were fewer pipeline events, bombings or interruptions. But it was actually down for a long period of time because of a landslide. So there's -- and that -- those repairs are essentially finished now, and we're hoping that pipeline will be up and running again in the next week or so. And then, in parallel with that, the pipeline south that goes into Ecuador continues to be repaired due to the damaged pipeline crossing -- across the river, across the border. So you're correct, we had fewer pipeline events, but there was a long drawn out repair process for the landslide damage on OTA, which is just now coming to closure. Now in terms of your other question, I guess, related to changes in guidance in our geologic expectations, recovery expectations, there's really no change. The fields continue to perform very well. Moqueta's production is growing, Costayaco is essentially stable, our other smaller, I'll call them, more minor fields in Colombia are performing as expected.

[Caio M. Carvalhal:]

Okay. I understand. And if you'll allow me for just a follow-up question on what my colleagues have already questioned in Bretaña, just to see if I correctly understood it. We could expect the first [indiscernible] for the fourth quarter. I'm not sure if you have a more specific guidance, let's say, in November or -- and then you planned -- I mean you target a 6-month period of the long-term test. So it could be turning to development or to full development phase somewhere close to mid next year. When you turn to development, when you turn from the long-term test to development, can we expect some -- should we expect some disruption or temporary disruption in production? Or will you be able to transition or to continue to maintain production from this long-term test while you drill the other ones and then you would see a more -- most production growth? So these are questions on Bretaña.

[Shane P. O'Leary:]

There's a number of things we're going to do. For the long-term test with the original wellbore, we expect just under the regulations we can produce that for at least 1 year. But there is precedent in Peru to have long-term tests extended beyond the 1 year. And of course, we will be trying to get an extension on that, and because the Aquitos refinery is where our crude is being delivered, it's unlikely that the refinery is going to want to see their supply cutoff. So I think our chances are good. We'll have that extended. In addition to that, as Dana mentioned, we're doing this duolateral trial well. So we'll be drilling a well in 2015, that's a multilateral, and that will also qualify for a long-term test. So again, we have 6 months of -- with an extension of another 6 months. So we will be flowing that well for at least a year and, again, we will try and get extensions that go beyond that year. So you can see yourself through to 2016 beyond when at least we'll have some level of production and cash flow coming out of Peru. And then, you're starting to get into the pace of the main field development, which will take -- needs more definition, and we're still defining what that's going to look like. But there should be some -- a good chance of continuity of production from these early test wells through to main field development.

[Operator:]

Mr. Coffield, there are no further questions at this time.

[Dana Coffield:]

I would like to, once again, thank everyone for joining us today. We look forward to speaking with you next quarter, and updating you on our progress. Thank you.

[Operator:]

Thank you. Ladies and gentlemen, this concludes the presentation. You may now disconnect and have a good day.