Gran Tierra Energy Inc.
Q2 2013 Earnings Call Transcript

Published: 8 Aug 2013

[Operator:]

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

[Dana Coffield:]

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 the quarter was $168.8 million, a 47% increase over the comparable period in 2012. Net income was $47.8 million compared with a net income of $13.1 million in the comparable period in 2012. Funds flow from operations increased to $200.1 million for the first half of 2013 from $116 million in the comparable period in 2012. Cash and cash equivalents were $282 million at June 30, 2013 compared with $212.6 million at December 31, 2012. As before, we remain debt-free. Operationally, we had a strong quarter. Shane will go through the results shortly, but in summary, the Moqueta fields in the Putumayo Basin in Southern Colombia continues to grow, with the limits of the field yet to be defined. The Moqueta-10 and 11 wells were drilled. The results, so far, are very positive, with additional reserve implications subject to further test results. In Peru, Gran Tierra Energy successfully tested the horizontal sidetrack of the Bretaña Norte 95-2-1XD exploration well in Block 95 at 3,095 barrels of oil per day. We are working towards booking reserves on the Bretaña structure before year-end 2013, and we intend to initiate long-term testing from the Bretaña Norte in the first quarter of 2014. Upon proving commerciality, this deal is expected to drive the midterm growth of Gran Tierra Energy. In Brazil, Gran Tierra successfully bid on 3 blocks in the recently completed 2013 Brazil Bid Round, thus increasing its land position in Brazil to 47,734 gross acres. Gran Tierra Energy's ongoing 3-well horizontal drilling campaign results to date have been inconclusive, but the positive data gathered continues to support the exploration play concept on our expanded land base. And more drilling and testing will be required to ultimately prove the concept. In Argentina, plans are underway to drill a second horizontal multi-stage fracture stimulated well in the third quarter of 2013 after the successful production test of the PMN-1117 horizontal well drilled in late 2012. Gran Tierra Energy is in the midst of one of our most exciting years in terms of potential reserve and production growth, with a very active capital program ongoing in the second half of this year. Our financial position remains strong, and we remain debt-free. And we'll continue to expect to fund this year's capital program with cash flow and cash on hand at current oil prices and production levels. Now let me turn the call over to James Rozon to discuss the financial results in more detail. James?

[James Rozon:]

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 to $32.6 million in 2012. DD&A expenses in 2013 included a $2 million ceiling test impairment loss in our Brazil cost center. The ceiling test impairment loss related to low realized prices and an increase in the estimate of operating cost. On a per BOE basis, the depletion rate increased by 23% to $31.29 from $25.34. The increase was mainly due to the Brazil impairment loss of $0.99 per BOE in 2013 and increased cost in the depletable base only partially offset by increased reserves. General and administrative, or G&A, expenses decreased by 33% to $11.7 million. Increased employee-related costs reflecting expanded operations were more than offset by increased recoveries from business units and higher G&A allocations to operating expenses and capital projects within the business units. G&A expenses per BOE in the second quarter of 2013 of $5.83 were 57% lower compared with $13.69 in the comparable period in 2012. In the second quarter of 2013, the foreign exchange gain was $12 million, comprising an $11.6 million unrealized noncash foreign exchange gain and realized foreign exchange gains up $400,000. The foreign exchange gain was a result of a net monetary liability position in Colombia combined with the weakening of the Colombian peso. For the second quarter of 2012, there was a foreign exchange loss of $4.8 million, comprising a $5.2 million unrealized noncash foreign exchange gain and a realized foreign exchange loss of $10 million. The realized foreign exchange loss primarily arose upon payment of the 2011 Colombian income tax liability during that quarter. We had net income in the second quarter of 2013 of $47.8 million compared to $13.1 million in the comparable period in 2012. In 2013, increased oil and natural gas sales, decreased G&A expenses and a foreign exchange gain were partially offset by increased operating, DD&A and income tax expenses. For the second quarter of 2013, funds flow from operations increased by 143% from $37.6 million to $91.5 million. The increase was primarily due to increased oil and natural gas sales, decreased G&A expenses and realized foreign exchange losses, partially offset by increased operating and income tax expenses. A reconciliation to net income is included in our second quarter 2013 earnings press release. Cash and cash equivalents were $282 million at June 30, 2013 compared with $212.6 million at December 31, 2012. The increase in cash and cash equivalents during the 6 months ended June 30, 2013 was primarily the result of funds flow from operations of $200.1 million, a $48.7 million decrease in assets and liabilities from operating activities, partially offset by capital expenditures net of proceeds from oil and gas properties of $179 million. In summary, we remain financially strong. As Dana said, we expect that our 2013 capital program of $454 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 update on our 2013 capital plan and outlook.

[Shane P. O’Leary:]

Thank you, James. The Moqueta field remains the near-term growth engine for Gran Tierra Energy, and 2 more important wells have now been drilled in our ongoing appraisal program for the discovery. The Moqueta-10 appraisal well was spud on April 7, 2013 and reached total depth on May 7, 2013. The well was intended as a water injection well targeting the far western flank of the Moqueta field to assist in pressure support. The Moqueta-10 well discovered oil in the T-Sandstone and Caballos formations. The T-Sandstone formation consisted of 65 feet true vertical depth gross reservoir or 58 feet true vertical depth of net reservoir thickness. It was perforated and tested from 6,105 feet to 6,180 feet measured depth for 81 hours at a rate of 609 barrels of oil per day of 26.2 degree API oil with a 0.3% water cut. The underlying Caballos formation consisted of 178 feet true vertical depth gross reservoir or 113 feet true vertical depth net reservoir thickness. It was perforated and tested from 6,276 feet to 6,470 feet measured depth for 202 hours at a rate of 343 barrels of oil per day of 27.5 API oil with a 0.3% water cut. No oil-water contact was encountered in either reservoir. The well was tested with a hydraulic jet pump and is intended to be used as an oil producer until water breakthrough occurs, and then will be converted to a water injector as originally planned. The Moqueta-11 appraisal well, drilled to the southern flank of Moqueta structure, was spud on June 19, 2013 and reached total depth on July 15, 2013. Initial drilling and logging results indicate oil through the Villeta T-Sandstone and the Caballos formations. Initial log interpretations suggest the top of the Villeta T-Sandstone is approximately 290 feet lower in the Moqueta-11 well compared to the lowest known oil encountered in the field at Moqueta-7 well, suggesting the oil column is 290 feet thicker than previously defined. The gross oil column in the Villeta T-Sandstone has now grown to 765 feet, and the gross oil column in the underlying Caballos reservoir has now grown to 960 feet. No oil-water contact is evident on logs, which, subject to testing, indicates additional oil potential exists further down the flank of the Moqueta structure. Gran Tierra Energy continues to anticipate receiving the Moqueta global environmental permit in the first quarter of 2014, which will enable the company to pursue delineation of the northeast portion of the Moqueta structure later that year, in addition to drilling more development wells to continue growing production. Needless to say, we continue to be very excited about the potential for the Moqueta field. Our most important field for maintaining our base production is the nearby Costayaco Field. The Costayaco-18 development well was spud on March 19, 2013 and reached a total depth of 8,857 feet measured depth on April 13, 2013. This well was put on production in the second quarter to assist in maintaining plateau production at the Costayaco Field. To date, we have seen no signs of plateau production decline in the field as production continues to exceed our expectations. Moving on to our recent Ramiriqui-1 oil discovery located in the Andean foothills trend of the Llanos Basin. Gran Tierra Energy, along with its operating partner, initiated long-term testing of the Ramiriqui-1 discovery on April 22, 2013, with Gran Tierra Energy's share of the current production at approximately 410 barrels of oil per day net after royalty. The nearby Mayalito-1 exploration well was spud on June 19, 2013. This well will explore a shallow prospect and further test additional deeper hydrocarbon bearing zones encountered, but not tested in the successful Ramiriqui-1 oil discovery well. This well is expected to reach total depth in late September. The next exploration well in Colombia is expected to be the Miraflor West-1 oil exploration well on the Guayuyaco Block. The well is expected to be spud in the third quarter of 2013. In Argentina, with the previous announcement of the successful flow test for the PMN-1117 well, the first fracture stimulated horizontal well in the Loma Montosa formation of Argentina, Gran Tierra Energy plans to replace 2 development wells, originally planned for the second half of 2013, with a second horizontal well into the Loma Montosa formation. Gran Tierra Energy has secured a drilling rig and expects to begin drilling the PMN-1135 horizontal multi-stage fracture stimulated well in August 2013. In Peru, following the successful first quarter 2013 production test from the Vivian formation sandstone reservoir in the Bretaña Norte 95-2-1XD exploration well, Gran Tierra Energy announced the successful production test from the horizontal sidetrack of the Bretaña Norte exploration well on May 28, 2013. A production test was conducted over the 1,595-foot horizontal length of the sidetrack, penetrating approximately 25 vertical feet at the top of the Vivian formation in the Bretaña structure. A series of tests were conducted, ultimately resulting in a flow rate of approximately 3,095 barrels of oil per day on natural flow with 0% water cut. Wellhead flowing pressure was increasing during the first test, indicating the formation was cleaning up. Cumulative production for both testing periods was approximately 3,552 barrels of oil, and testing was concluded when available storage capacity had been achieved. Gran Tierra Energy has initiated a preliminary Front End Engineering Design study for the Bretaña field. In addition, a 382-kilometer 2D seismic program has been initiated to provide a more detailed map of the Bretaña structure, in addition to maturing a separate independent exploration lead on Block 95. Importantly, Gran Tierra Energy has successfully transported by barge and sold its first test oil to the Peru (sic) [Petroperu] S.A. refinery in the city of Iquitos. This is one of several monetization options for crude from Bretaña under evaluation. Gran Tierra Energy is working towards booking reserves on the Bretaña structure by year-end 2013 and intends to initiate long-term testing from the Bretaña Norte well in the first quarter of 2014. In Brazil, the data collected during the ongoing 3-well horizontal drilling exploration campaign targeting 2 separate unconventional plays in the Recôncavo Basin continues to be evaluated, but results remain inconclusive to date. The first horizontal sidetrack well, GTE-5, on Block 142 was a re-entry sidetrack well into the 1-GTE-01-BA pilot well, which encountered a 121-foot tight oil-saturated Gomo Sandstone. The GTE-5 sidetrack drilled 1,739 feet of gross horizontal section in the target Gomo Sandstone and was completed with a 4-stage fracture stimulation. The well tested water, suggesting that the oil saturations were not sufficiently high enough to flow oil. Despite this, Gran Tierra Energy remains confident that the concept is still promising and future wells will target areas with higher oil saturations. The second horizontal well, GTE-6 [ph], was also a re-entry sidetrack well into the 1-GT-2-BA [ph] pilot well on Block 129. The GTE-6 horizontal well was targeting an oil bearing interval in the Candeias shale. A 1,870-foot horizontal section was successfully drilled with excellent oil shows throughout. A 6-stage fracture stimulation was completed, and based on microseismic monitoring data, the final 2 fracture stages had greater fracture heights than planned and were inadvertently frac-ed into a lower saline water-bearing zone. Gran Tierra Energy is currently planning to reenter the wellbore to isolate the final 2 stages in order to test the shale interval. The third horizontal well, GTE-7 [ph], was sidetracked from the original wellbore on Block 155 and is currently drilling ahead, targeting the shale oil interval. The intent is to drill a 1,640-foot horizontal section and test it with multi-stage fracture stimulation. Gran Tierra Energy anticipates drilling and setting the completion string by the first week of August with fracture stimulation planned for September. The next planned well is the GTE-8 [ph] well, which will be a deviated well targeting the oil saturated shales. The primary objective of the well will be to cut and retrieve up to 177 feet of core to be utilized for detailed oil shale special core analysis studies to gain critical information regarding the oil shale play. Based on the growing volume of technical data acquired to date, Gran Tierra Energy believes that tight oil sandstone and shale oil reservoir targets in the Recôncavo Basin represent a valuable and material opportunity for future development. As a result, Gran Tierra energy successfully bid on 3 blocks in the recently completed 2013 Brazil Bid Round administered by Brazil's ANP. The 3 blocks, 86, 117 and 118, are located adjacent to and north of Gran Tierra Energy's core existing areas in the Recôncavo Basin onshore Brazil and offers additional potential on the company's current exploration play trend that will enable Gran Tierra Energy to leverage its growing knowledge of the basin. The 3 blocks encompass 20,658 gross acres of land under an initial 3-year exploration period. Upon final approvals from the ANP, Gran Tierra Energy's total acreage in the Recôncavo Basin will be 47,734 gross acres. Gran Tierra Energy's conventional production in Brazil is approximately 1,000 barrels of oil per day gross. And we are in discussions with Brazil's National Hydrocarbon Agency to have gas flaring restrictions lifted to move production up to 2,000 barrels of oil per day gross. Longer-term, we are discussing with Petrobras the option to tie in our gas to eliminate the need to flare. Let me now hand it over to Dana for a brief capital spending update and concluding remarks.

[Dana Coffield:]

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:]

[Operator Instructions] And your first question comes from the line of Caio Carvalhal with JPMorgan.

[Caio M. Carvalhal:]

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.

[Dana Coffield:]

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:]

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?

[James Rozon:]

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.

[Operator:]

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

[Jamie Somerville:]

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?

[Dana Coffield:]

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.

[Jamie Somerville:]

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?

[Dana Coffield:]

Right.

[Jamie Somerville:]

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?

[Dana Coffield:]

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 --

[Jamie Somerville:]

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

[Dana Coffield:]

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.

[Operator:]

Your next question comes from the line of Matt Portillo with Tudor, Pickering, Holt.

[Matthew Portillo:]

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?

[Dana Coffield:]

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:]

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.

[Dana Coffield:]

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:]

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?

[Dana Coffield:]

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:]

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?

[Dana Coffield:]

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.

[Operator:]

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

[Jamie Somerville:]

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?

[James Rozon:]

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

[Dana Coffield:]

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:]

Okay. So the pace at which you can develop pressure support is really defining your capacity in the plateau levels?

[Dana Coffield:]

At Moqueta, that's correct.

[Jamie Somerville:]

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?

[Dana Coffield:]

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.

[Jamie Somerville:]

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?

[Dana Coffield:]

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

[Operator:]

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

[Pedro Medeiros:]

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?

[Dana Coffield:]

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.

[Pedro Medeiros:]

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...

[Dana Coffield:]

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.

[Pedro Medeiros:]

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?

[Dana Coffield:]

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.

[Pedro Medeiros:]

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?

[Dana Coffield:]

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.

[Pedro Medeiros:]

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?

[Dana Coffield:]

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.

[Pedro Medeiros:]

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?

[Dana Coffield:]

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.

[Operator:]

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

[Unknown Analyst:]

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.

[Dana Coffield:]

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.

[Operator:]

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

[David Popowich:]

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.

[David Popowich:]

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?

[Dana Coffield:]

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.

[Operator:]

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

[Justin Anderson:]

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?

[Dana Coffield:]

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

[Justin Anderson:]

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?

[Dana Coffield:]

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

[Justin Anderson:]

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?

[Dana Coffield:]

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.

[Justin Anderson:]

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

[Dana Coffield:]

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.

[Operator:]

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

[Darren B. Engels:]

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?

[Dana Coffield:]

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.

[Operator:]

Your next question comes from the line of David Phung with Crédit Suisse.

[David Phung:]

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?

[Dana Coffield:]

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:]

Right. So I guess you can't comment on the deliverability that you saw added?

[Dana Coffield:]

That's correct.

[David Phung:]

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?

[Dana Coffield:]

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:]

So do you have an anticipated date on when you're going to production test that second well?

[Dana Coffield:]

Probably -- which well, the one we frac-ed already?

[David Phung:]

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.

[Operator:]

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

[Jason Crumley:]

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.

[Operator:]

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