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Executives

Dana Coffield - Chief Executive Officer, President, Executive Director and Member of Reserves Committee

James Rozon - Acting Chief Financial Officer, Principal Accounting Officer and Corporate Controller

Shane P. O’leary - Chief Operating Officer

Analysts

Nathan Piper - RBC Capital Markets, LLC, Research Division

Jamie Somerville - TD Securities Equity Research

Michael Letros

George Toriola - UBS Investment Bank, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

John Malone - Global Hunter Securities, LLC, Research Division

Ian Macqueen - CIBC World Markets Inc., Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Brad Virbitsky

Gran Tierra Energy (GTE) Q3 2012 Earnings Call November 7, 2012 4:00 PM ET

Operator

Good day, ladies and gentlemen, and welcome to Gran Tierra Energy Results Conference Call for the 9 months ended September 30, 2012. My name is Angela, 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, Tuesday, November 7th, 2012 at 4:00 p.m. Eastern Standard Time.

Please be advised that in addition to historical information, certain comments made during this conference call, particularly those anticipated -- anticipating future financial performances, business prospects and overall operating strategies, constitute forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.

Such statements may be identified by words such as anticipate, believe, estimate, expect, intend, predict and hope or similar expressions. Such statements, which include estimated or forward-looking production and financial information or results, are based on management’s current expectations and are subject to a number of factors and uncertainties which could cause actual results to differ materially from those described in the forward-looking statements.

Listeners are urged to carefully review and consider the various disclosures made by Gran Tierra Energy in its reports filed with the Securities and Exchange Commission, including those risks set forth in Gran Tierra Energy’s quarterly report on Form 10-Q filed with the SEC on November 7, 2012 and in its annual report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission February 27, 2012.

If one or more of these risks or uncertainties materialize or if the underlying assumptions prove incorrect, Gran Tierra Energy’s actual results may vary materially from those expected or projected. Listeners are urged not to place undue reliance on forward-looking statements made in today’s conference call. Gran Tierra Energy assumes no obligation to update these forward-looking statements other than as may be required by applicable law or regulation.

Today's conference call also includes the non-GAAP measure funds flow from operations. The press release disseminated by Gran Tierra Energy this morning includes a reconciliation of this non-GAAP item with the company's GAAP net income or loss, as well as information about why management believes this measure is useful in evaluating the company's performance, and is available on Grand Tierra Energy's website, www.grantierra.com.

All dollar amounts mentioned in today’s conference call are in U.S. dollars, unless otherwise stated.

Finally, this earnings call is the property of Gran Tierra Energy Inc. Any copying or rebroadcasting of this call is expressly forbidden without the written consent of Grand 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.

Dana Coffield

Thank you, and thank you for joining us for Gran Tierra Energy's Third Quarter 2012 Results Conference Call. With me today is Shane O'leary, our Chief Operating Officer; and James Rozon, our Chief Financial Officer.

This morning, we disseminated a press release that included detailed financial information about the quarter. In addition, Gran Tierra Energy's report on Form 10-Q for the 9 months ending September 30, 2012 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 then take a few minutes to discuss the key aspects of this quarter's financial results. Shane will discuss our third quarter operations, then I will return to provide an outlook and some closing remarks.

Overall, Gran Tierra Energy had a strong third quarter, reaching record levels of production and revenue, with associated strong funds flow from operations. We added significantly to our exploration land base in Colombia and Peru and have most recently had very encouraging results from the Moqueta-7 appraisal well.

Gran Tierra Energy's production in third quarter averaged 19,491 barrels of oil per day net after royalties and inventory adjustments. 96% of this was oil and natural gas liquids.

This production was comprised of 15,664 barrels oil equivalent per day in Colombia where it is 99% oil and natural gas liquids; 3,745 barrels of oil equivalent per day in Argentina; and 82 barrels of oil per day in Brazil.

This was a 6% increase compared to the third quarter of 2011, primarily due to the excellent reservoir performance from the Moqueta and Costayaco fields in Colombia and new oil wells in Argentina.

The increase in our production was partially offset by the impact of oil delivery restrictions by disruptions in Ecopetrol-operated OTA pipeline in Colombia. Fortunately, the number of disruptions has significantly decreased compared to the first half of 2012.

We continue to work with authorities and outside parties in Ecopetrol to look at multiple transportation and storage options to help mitigate the impact of pipeline disruptions. These include more continuous use of the Oleoducto San Miguel pipeline, which connects Ecopetrol's Orito gathering facilities to Ecuador; additional storage at Orito, in combination with higher capacity utilization of the OTA pipeline when it is operational; and higher volumes of trucking to other delivery points.

And we added to our prospective land position in Colombia by jointly submitting the winning bid for Sinu-1 and Sinu-3 Blocks and improved by assuming 100% working interest and operatorship of Blocks 123 and 129, all subject to customary government approvals. New blocks and additional working interest add substantial new exploration upside to our exploration portfolio testing in the coming years.

Now subsequent to the end of the quarter, we have some very encouraging results from the Moqueta-7 appraisal well. The well encountered the main T Sandstone and Caballos reservoirs approximately 45 feet shallower than prognosis. This indicates the Moqueta structure is broader and has more areal extent to the west than previously interpreted. The reservoirs are interpreted to be oil-bearing from mud logs and electric logs.

In addition, 3 separate fault blocks were subsequent -- subsequently crossed with interpreted oil-bearing Caballos Sandstone reservoirs in the first 2 blocks. The Caballos section encountered in the third block was water-bearing.

A total of 215 feet of potential net pay has been encountered in Moqueta-7, with no oil-water contacts encountered in the main field, nor in the 2 new oil-bearing fault blocks encountered by the well.

Actual oil pay thickness is subject to testing, which has begun and is expected to be completed before the end of November.

Now let me turn the call over to James to discuss the financial results. James?

James Rozon

Thanks, Dana, and good afternoon, everyone. Revenue and other income for the third quarter of 2012 was $168.9 million, a 12% increase from the same quarter in 2011 due to increased production and increased realized prices. The average price received per barrel of oil increased by 4% to $96.75 from $92.76 from the same quarter in 2011.

Operating expenses for the third quarter of 2012 were $36.3 million or $20.24 per BOE compared with $21.7 million or $12.86 per BOE in the comparable quarter in 2011. The increase in operating expenses was mainly due to an increase of $13.8 million in Colombia, primarily due to Ecopetrol-operated Trans Andean oil pipeline oil transportation costs, included as operating costs due to the change in sales point in February 2012, and increased trucking due to pipeline disruptions.

Depletion, depreciation, accretion and impairment expenses for the third quarter of 2012 were $45 million compared with $49.9 million for the comparable quarter in 2011.

On a per BOE basis, DD&A expense in the third quarter of 2012 were $25.12 compared to $29.50 in the comparable quarter in 2011, representing a 15% decrease. The decrease resulted from increased reserves and lower impairment charges, which more than offset increased future development costs in the depletable base.

General and administrative expenses in the third quarter decreased by 21% to $12.9 million, primarily due to increased recoveries; increased capitalized costs in Peru, due to increased exploration and development activities; and the absence of interest expense of $0.8 million relating to the Petrolifera debt, which was repaid in August 2011. These G&A expense reduction were partially offset by increased employee-related costs reflecting the expanded operations.

G&A expenses per BOE were $25 million -- or sorry, 25% lower than in the third quarter of 2011 at $7.19, due to the same factors and increased production.

Included in the third quarter of 2012 results is a foreign exchange gain of $1.3 million, which included an unrealized foreign exchange gain of $2.1 million, which was due to the weakening of the Colombian peso against the U.S. dollar and included the translation of current and deferred tax liabilities denominated in Colombian pesos.

Gran Tierra Energy had net income for the third quarter of 2012 of $44.6 million compared with $49.1 million in the same quarter in 2011.

In the third quarter of 2012, higher oil and natural gas sales and lower DD&A and G&A expenses were more than offset by increased operating and income tax expenses and lower foreign exchange gains.

Funds flow from operations increased by 24% to $89.9 million in the third quarter of 2012 from $72.8 million in the comparable quarter in 2011. The increase was primarily due to higher oil and natural gas sales, decreased G&A expenses, partially offset by increasing -- or increased operating and income tax expenses.

A reconciliation of net income is included in our third quarter 2012 earnings press release.

Cash and cash equivalents were $127.6 million at September 30, 2012 compared with $351.7 million at December 31, 2011. The change in cash and cash equivalents during the 9 months ended September 30, 2012 was primarily the result of funds flow from operations of $206.5 million and proceeds from issuance of common shares of $3.8 million being more than offset by an increase in assets and liabilities from operating activities of $190.6 million, capital expenditures of $222.1 million and a $21.7 million increase in restricted cash.

In summary, Gran Tierra Energy remains financially strong, with the expectation that our 2012 exploration and development capital program of $380 million is to be funded entirely from cash flow from operations and cash on hand, given current production and oil prices.

That concludes my comments. I would like to turn the call to Shane for an update of Gran Tierra Energy's 2012 capital plan and outlook.

Shane P. O’leary

Thank you, James. Gran Tierra Energy remains focused on its 2012 capital program. During the third quarter of 2012, we commenced drilling a Moqueta-7 delineation well on the Chaza Block in Colombia, which was spud on September 6, 2012.

As Dana previously explained, the results are very encouraging, and we have begun testing the oil-bearing zones that were encountered. Once testing is completed on M-7, we plan to move the rig over to drill Moqueta-8, most likely in the southern part of the field, with the intent to use this well as a producer.

Costayaco-16 development well on the Chaza Block, which spud on June 6, 2012, was completed during the third quarter and is currently on production. We plan to drill the Costayaco-17 well in the northern area in the fourth quarter. It's part of our ongoing exploitation program to maximize recovery of reserves from the Costayaco Field.

Water injection on the western flank of the field has reached 23,000 barrels per day. And the pressure response continues to be excellent, with increasing pressures being observed in both the Caballos and T Sand reservoirs.

The success of this program is a major factor contributing to the 33% increase in proven reserves in Costayaco announced last quarter and record production levels achieved this quarter. As a result of this success, plans are underway to further expand the water injection program.

In parallel with our drilling activities, we also continued with the acquisition and processing of 3D seismic facilities work in the Costayaco and Moqueta fields.

Finally, in Colombia, the La Vega Este-1 oil exploration well in the Azar Block was plugged and abandoned during the quarter after finding noncommercial heavy oil.

For the remainder of 2012, we plan to drill 1 gross oil exploration well on each of the Turpial Block and Sierra Nevada Blocks.

Moving on to Argentina. During the third quarter, we began the drilling phase of our new exploitation program for Puesto Morales, following a detailed reservoir and subsurface study. The program involves a combination of new production injector wells and workovers.

Of the 5 development wells drilled in the Puesto Morales Block, 4 of these wells are producing and 1 is a water injection well. The sixth development well was spud on October 1, 2012. So far, results are meeting expectations. Polymer flood pilot test program is also planned for this quarter.

On the Rinconada Norte Block, drilling commenced on 2 development wells, and both are currently being completed.

Turning to Peru. During the third quarter of 2012, we continued civil construction of a drilling platform and dock facility on Block 95. We expect to spud the Bretaña well in December, and it is expected to allow further appraisal of the discovery made by Amoco in 1974, which flow at 807 barrels of oil per day.

Subsequent to September 30, 2012, as mentioned, we assumed 100% working interest in operatorship of Blocks 123 and 129 in Peru, subject to government approval, when the other 2 partners made strategic decisions to exit Peru and assigned their interest in these blocks to Gran Tierra Energy. Over $50 million of 2D seismic has been acquired on these Blocks. This data has defined very large, structural closures up-dip of the prolific Marañon Basin, a long strike from more recent oil discoveries being -- fairly being developed.

Finally in Brazil, the ANP has approved the purchase of the remaining 30% interest in our 4 blocks in Brazil.

In Block 155, we drilled and completed 2 development wells in the second quarter in the Tiê field. In the third quarter, we submitted the necessary documentation for the declaration of commerciality and anticipated production, and received approval in September 2012.

The 2 development wells in the Tiê field, together with the original discovery well, is producing approximately 1,000 barrels of oil per day gross or 850 barrels of oil per day net after royalties.

Our production level is restricted by gas flaring limitations. We have commenced discussions with Petrobras to tie in to a nearby gas line to eliminate flaring and enable production from the Tiê field to be increased up to 2,000 barrels a day.

In addition, the drilling of our first horizontal well in the Candela's [ph] tight oil play has been initiated.

Gran Tierra Energy has revised its capital expenditure program for 2012 to $380 million from $396 million. The capital budget revisions are not expected to have an impact on 2012 production expectations.

Based on the work completed to date and additional activity planned for the fourth quarter, we anticipate a 2012 exit production rate between 20,000 and 21,000 barrels of oil per day net after royalty before inventory adjustment.

That concludes my comments. I'd now like to turn the call back to Dana for concluding remarks.

Dana Coffield

All right, thank you, Shane. Gran Tierra has enjoyed exploration drilling success, appraisal drilling success and development drilling success in the first 3 quarters of 2012, growing reserves and production in the process.

Current production is that near record levels, averaging approximately 20,000 barrels of oil equivalent per day net after royalties and inventory adjustments.

In addition, we have grown our exploration land position, which we plan to use for -- to further mature our exploration portfolio for the future. We are now working on our 2013 capital plan that should be finalized and announced in December of this year.

We expect to continue to execute this year's capital program from cash flow and cash on hand and are intending to do so again next year as we continue to grow our company, with our growing base of reserves and production and our expanding exploration portfolio and our strong balance sheet.

Now that concludes our prepared remarks for today. We would now be pleased to answer any questions you might have. Angela?

Question-and-Answer Session

Operator

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

Nathan Piper - RBC Capital Markets, LLC, Research Division

Quick questions. First of all, on Moqueta, could you describe where you think the bottom end of expectations should be in terms of the size of Moqueta? Secondly, where the rock properties you encountered in Moqueta-7 the same as you've already encountered with the previous drilling, and is that the case with the other 4 blocks that you encountered? And I guess lastly, if we let our imaginations run away with ourselves, where could this Moqueta structure get to? I mean, is there a chance -- I know you're drilling kind of a Costayaco Norte well as well, is there a chance that Moqueta and Costayaco are part of 1 larger structure.

Shane P. O’leary

Nathan, thanks. I'll answer your questions backwards. It's extremely unlikely that Moqueta and Costayaco are connected. They're very much different depths, different pressures, oil saturations, part of the same flowing system, but they're not connected fields. So that's that question. The petrophysical properties or the rock properties are generally consistent with the Moqueta-7, a lot of interpretations and cuttings with the previous wells that have been drilled in the field. I believe your first question is, what is the minimum size [ph] field to be. As you know, we have -- I think last year, we had around 12 million barrels of 3P reserves booked for the field based on the oil known -- oil calls known at that time. Obviously, it's now much larger. So it's certainly much larger than reserves we had at end of last year. But until we get more information, basic tests are the only thing that have been encountered. And then that remap to structure is premature to how small or big it is, other than it is bigger than previously interpreted. Did that answer your questions?

Nathan Piper - RBC Capital Markets, LLC, Research Division

I guess, after a fashion. But one quick follow-up on a different topic. Can you give a sense then for the chance of success of the drilling in Peru later on this year, just to change subject?

Shane P. O’leary

Yes, the well we're going to drill in Peru has, I'll say, extremely high geologic chance of success. I mean, we know the field is there. We have the quality 2D seismic data. We're not drilling too far away from the existing discovery well. I think around 1 kilometer or so. So it's a very -- it's an exploration well because we are going to explore some deeper horizons. The existing horizon was to prove an oil. We're almost certainly going to encounter that same horizon with oil. It has a very high chance of success.

Nathan Piper - RBC Capital Markets, LLC, Research Division

And what's the commercial discovery in Peru in terms of -- what size you need to make it commercial?

Shane P. O’leary

I think in our base case, we're assuming 30 million barrels recoverable for the field, some of our base development. That's not the minimum field size. That's our base case.

Operator

And your next question will come from the line of Jamie Somerville with TD Securities.

Jamie Somerville - TD Securities Equity Research

I'm just going to continue asking on Moqueta. As you -- presumably what you found in the deeper zones was a bit of a surprise to you, so I'm just wondering if you can talk around how you're going to -- how long are you going to have to take before you come back and appraise the area further. I assume you're going to have to test, but the western side of Moqueta clearly warrants further appraisal drilling, but how much have you got to do? Is Moqueta-8 still going to go ahead and drill the northeastern or eastern side? And then, do you expect to come back fairly quickly to the western side? And what does it -- what does this surprising result mean for the area in general outside of Moqueta?

Shane P. O’leary

Yes, the -- there's a lot of appraisal work, a lot of appraisal drilling yet to be done. And this -- our -- the recent results is going to add to the work that needs to be done. The main challenge we have been facing and are going to face in the coming 6 to 8 months is not being able to drill from new drilling locations. We're still waiting for the global environmental permit to drill wells quickly and efficiently in optimal locations. So we're constrained on where we can reach in the field for the appraisal program by our existing exploration pads. So we are going to have to come back to do more appraisal drilling on the west. These new fault blocks are going to require additional appraisal drilling. We expect these fault blocks to essentially extend around the western, southern, eastern perimeter of the field because of the structural geometry of the field is -- the thrust faults are generally trending towards the south, repeating in the sections around the west, south, and east lines of the field. Moqueta-8, specifically have been planned to drill to the east. Our current plans are to drill the wells towards the south because of the risk of reaching to the east, as I said, from these long deviated wells. And so right now, we're going to -- looking at a lower-risk development well location towards the south, and that would be drilled as a producer. I missed the other comments.

Jamie Somerville - TD Securities Equity Research

Within the core of the field, is it worth -- are any of the existing wells or Moqueta-8 worth deepening to test for these different fault blocks?

Shane P. O’leary

That's a very good question, and that's what we're trying to understand ourselves right now. These fault blocks have been encountered on the -- say, on the flanks of the field where there is very poor seismic data, very poor quality seismic to interpret, which is why we hadn't recognized it before. Now that we know who were there, we are evaluating or reinterpreting the existing 3D seismic data to see if we can interpret these reservoir sections underneath the main field and how far towards north under the main field they may extend. So that's a work in progress. There may be an opportunity to use other wells or other existing pads to test that concept.

Jamie Somerville - TD Securities Equity Research

Shane, I didn't mean to cut you off there, but I'm going to add another question, which is, just I'm intrigued with your intention to frac the Loma Montosa in Puesto Morales, I was wondering since that formation as you're pointing out has never really been frac-ed before in the Neuquen Basin. What drew your interest to it -- beyond the oil in place that you presumably see, but what are the rock characteristics that you see that make you think that fracture stimulation is going to have a material difference and be a commercially exploitable technique in that area?

Shane P. O’leary

Well the idea behind the horizontal well program in the Loma Montosa is really just part of the overall strategy for Puesto Morales, where we have something like 70 million to 80 million barrels in place and we've only had a recovery of around 15% to 16% to date, which is extremely low, probably half of what it should be. So our new waterflood program, our polymer pilot test program, our new injector flood pattern are all directed with the same aim of increasing the recovery. The Loma Montosa, particularly, has not performed very well on vertical wells because it's a little bit tighter. And there's never been a horizontal frac well tried on that formation, which looks like it's ideal for it. So this was the first one. We've now drilled the well, and we're in the process of doing the -- running the completion. And the aim is to just increase the production from the field, and with -- we have some reserves booked in the Loma Montosa because of vertical wells, and we hope to increase that if we can improve the economics of that particular horizon. So it's just -- it's all part of enhancing the economics and recovery from Puesto Morales, which has been underexploited, for lack of a better word.

Jamie Somerville - TD Securities Equity Research

I'm sorry, but could you talk to the size of frac that you're planning to do, and whether you found services easy to access if you're planning to start that in the end of November?

Shane P. O’leary

We were planning -- I think we were planning a 6-stage frac. We've cut that back based on what we've seen in the reservoir, or I think we're going to frac now a total of about 300 feet of horizontal section. So the program has been cut to 3 or 4 fracs. Equipment-wise, we're working with Schlumberger, and it's high hopes for Argentina when it comes to this type of technology. But it's still very, very -- in the very infant stages in Argentina, and it is hard to find frac sand and things like that. So this is very much a pilot, and we'll have to do more to procure the materials and so on for a larger program. But we should get through this one and see where we go from here.

Operator

And your next question will come from the line of Michael Letros with Libra Advisors.

Michael Letros

Just 2 questions that are related. One is, can you just clarify how much CapEx you would need to spend to maintain flat production? And then, I guess in the context of what we're seeing in the markets, a huge appetite for yield and frankly, the very inexpensive valuation for Gran Tierra, would you consider with the Board at some point considering when maybe deploying some of the free cash flow and returning it to shareholders?

Dana Coffield

This is Dana. I'll answer the second question. The free cash flow, of course, is still being, right now, budgeted for drilling operations, primarily potential new developments that are pending, such as the growing capital need we're going to see at Moqueta and in Peru. But we have thought of other uses for the capital or for our cash should there be too much available. And, of course, dividends has been the -- versus a buyback has been an option the Board has been considering and still considers. At this point in time, though, we're still seeing more value in that and enough money to work new wells and finding new oil. But we have, also, been keeping a small reserve in place for potential acquisitions. And we have, in fact, this year been doing some acquisitions of, in particular, of buying out our working interest partners in our lands because we see a lot of value, as I said before, in our own existing land. So your question is a good question. It's up to the board, has considered and still considering, but at this point in time, not planning on any dividends. Shane, I think I have an answer for your maintenance capital question.

Shane P. O’leary

Well, I mean, we're not quite at the very mature phase of Costayaco or Moqueta, obviously. So it is development capital that continues to be spent on development wells, the waterflood facilities. If I had to -- and in Brazil, and now we've got production in Argentina, obviously, where it's a more mature field and there is ongoing drilling, we've got a new program. To add it all up, we're probably in the order of $150 million to $200 million to keep growing the production base that we have in Colombia, Argentina and Brazil. And then, the rest of our capital is directed at exploration of oils and so on. So [indiscernible]

James Rozon

Future CapEx, like, $170 million [indiscernible]

Shane P. O’leary

Sorry?

James Rozon

Yes, right.

Shane P. O’leary

Yes, it's about -- I think in our reserve report, we've got about $170 million of development capital. So it's in that order.

Operator

And your next question will come from the line of George Toriola with UBS.

George Toriola - UBS Investment Bank, Research Division

I just want to sort of explore Moqueta a little further here. So just to the south of and west of Moqueta-8, how far out -- what is the absolute -- the fault to the west, I believe, how far out is that fault from Moqueta-8, and what do you see as the absolute maximum sort of step-out distance you would imagine from that well?

Dana Coffield

It is actually a whole series of faults, not just 1. In fact, the well we just drilled went through 3 faults. So there's, I don't know, 5 or 6 or hole or even more that we can't see in the seismic section of stacked thrust sheets. The maximum step-out that we're comfortable doing from our pads, I think is around 2 kilometers, our reach from the existing pads. So we can't get to the, say, the limits of the structure from the existing pads.

George Toriola - UBS Investment Bank, Research Division

Okay. So potentially, are you going to be -- your next -- your appraisal well, are you going to be doing that from a different location or are you just going to try to...

Dana Coffield

We have to use -- for instance, Moqueta-8 will be drilled from the same pad as Moqueta-7, which is also the same pad as Moqueta-4. So we'll be drilling in a different direction, drilling to the south, southeast.

George Toriola - UBS Investment Bank, Research Division

Okay. And then, I mean, in terms of -- I sort of went through this math and I wondered sort of maybe point out, we're potentially wrong here, but when I go through the math, obviously, depending on where your context is on that side, this potentially could be -- I think I get something that could be as much as 10 million barrels of recoverable reserve adds through the different zones here. Is that out of the realm of the [indiscernible], the way you look at this here?

Dana Coffield

Not at all. I mean, there is a log normal dispute -- log normal distribution of possible field sizes that are outside the known area and that's certainly within the range of that distribution. There's variation in aerial extent of the structure. There's variation in the height of the oil column. Both of these, we've identified very discreetly with the last one we just drilled. Now we have these additional pools, but certainly your number certainly is within that distribution easily.

George Toriola - UBS Investment Bank, Research Division

Okay. And then what about to the north and east there in terms of the -- what -- how do you look at the north and east compared to what you've seen in the south and west here with respect to further expansion of the Moqueta field so to speak?

Dana Coffield

Yes, the northeast, a long strike and in my view would be a mirror image of what we're seeing today in the southwest to what we just drilled, geologically or structurally. The challenge we have, in fact, it used to be called as Moqueta East Prospect, an exploration prospect. Now with the new data, it looks like it's whole one continuous broad dome. The challenge we have is not having an optimally well-placed drilling location. Very difficult for us to drill that far to the east to test that potential from our existing drilling pads. So the top of that area, we're assuming will have a gas cap like we have in the discovery well. So we've got to get beyond the edges of the gas cap back to the oil column. This is what we're doing on the southwest side, but we just have not been able to do that yet to the northeast.

George Toriola - UBS Investment Bank, Research Division

Yes, yes. And the way -- and that's just a question of topography of what's -- that's what you're talking about here?

Dana Coffield

The issue is we don't have a global environmental permit, which allows us to build a new location, a new drilling location anywhere we want. We've begun the process. We submitted the application for this global environmental permit following our environmental field work and community consultations. But that permit has not yet been approved, so we're still restricted on what we can do on the surface.

George Toriola - UBS Investment Bank, Research Division

Okay, okay. And then in terms of when do you think you'll get that permit, though?

Dana Coffield

Right now, it's something like the middle of next year.

George Toriola - UBS Investment Bank, Research Division

Okay. But would you -- so essentially is that when you'll be able to go back and test that pad, or you'd -- I mean, I don't know if you can do anything different until you are able to reach outside of the gas cap.

Dana Coffield

We're gaining experience with each of our deviated wells we're currently drilling and as such, given us more comfort with the design of our well bores for these long-reach deviated wells. So we may be able to get out there with more experience, but it's going to be challenging is the short answer.

George Toriola - UBS Investment Bank, Research Division

Okay. And then do you see this as not connected? It's Moqueta. As you see the -- for example, the Caballos, it's not connected to the Caballos that's in the main part of Moqueta, so to speak. It's not one pool?

Dana Coffield

These 2 additional Caballos zones, at first, do not appear to be connected but we're going to need test data to confirm that, along strike. As you go around the rim of the field, they may be connected. But our base assumption now is that they are not connected.

George Toriola - UBS Investment Bank, Research Division

Yes, there're not. Okay, I guess, the last question for me is, so in terms of the development plan for Moqueta, it seems to me that, that development plan would continue to unfold as you learn more and more about Moqueta. So when do you think would -- we can see a sort of broader development plan with sort of production growth rates and things like that for Moqueta as a whole?

Dana Coffield

The key -- well, the key part of the development plan that we're working on now, which will lead to production growth that you're asking about, is the need for us to implement water injection for pressure support in the main field. Because of the gas cap, we can't allow the pressure to drop in the field, below oil-saturated gas. If the pressure drops, then the gas comes out of the oil into the wellbore. So right now, we're looking at the existing wellbores to evaluate which, if any, we can use for water injection. And we're also looking at drilling long-reach deviated wells to act as water ejectors. The key right now for production growth is pressure support, and that's going to be the program we're going to be working on over the next 3 to 6 months. So you probably won't see -- you won't see material production growth, I'll say, in the next 3 to 6 months from Moqueta.

George Toriola - UBS Investment Bank, Research Division

Okay, that's helpful. And then just the last question here. The difference between your booked 2P reserves on Moqueta and the 3P number, is that just the field performance or that has to do with aerial extent as well?

Dana Coffield

No, that's not field performance. It's purely on the volumetrics down to the lowest known oil at that time and then cutting off the area at any faults. So they gave us no additional reserves in the area outside any fault boundaries nor did they give us any oil upside beneath the lowest known oil in any reservoir. So those numbers are, I'll say, grossly out of date right now.

Operator

And gentlemen, your next question will come from the line of Matt Portillo with Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just a few questions for me. Just in terms of Llanos-22, can you give an update there, maybe plans for first production? Are you still expecting to potentially achieve that before year end? And in terms of reserves, what do you need to see to be able to book reserves on that initial discovery?

Dana Coffield

CEPSA, the operator, is telling us they'd like to bring that on probably at the beginning of December as a test production. It will be constrained with a flaring restriction. And so it'll be fairly modest production. I think they're talking about 700, 800 barrels a day sort of thing, gross, initially. So it can get -- I mean, you remember -- you recall that the test was 2,500 barrels a day. So certainly, we could bring that well on -- at a higher rate, but it would require tying in the gas to the Echion system, which isn't that far way, and we were in discussions with Echion about doing that. So I mean, that's sort of the next step. And we do need production history to really determine how big this thing is because, in our estimation, not enough of the Mirador formation was tested. They only tested the very upper interval and we had a disagreement with the operator about how much to test on that. And that's going to impact assessment of reserves. Until we can get good production history to demonstrate what we think it's -- what the reserve tank size is based on pressure depletion. So that's sort of the order of magnitude that we're looking at.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then, as you think about your 2013 plans there, do you have any initial plans on kind of appraisal or exploration for that block?

Dana Coffield

Well, there's one more well commitment that must be drilled. And it could be drilled as an appraisal well to the Ramiriqui discovery. I would have to say it's more likely we'll go to the northern corner of this block where there's a really attractive-looking exploration play that's emerging and more likely, there's a consortium to drill that than an appraisal well but it hasn't been decided yet.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then, as we think about quickly just down to Peru, can you talk about your plans in Peru on Block 95, how that's progressing, how we should think about kind of timing to TD on that well? And then, on the remaining blocks, obviously, you've picked up a high working interest here on 123 and 129 and then also in some of your southern blocks. How do you view potentially farming out your acreage and potentially bringing in partners to help reduce risk capital?

Shane P. O’leary

Okay. I'll talk about 95 and then turn it over to Dana. But 95, we're expecting to spud in the first or second week of December. We are in the process of constructing a platform. This is an area that floods quite easily and so we've had to build a platform to sit the rig on. It's probably a 60-day well so results will be coming in sort of February time frame. And then we've got some ideas around an early oil scheme and things like that. It all depends on what we find in terms of how fast we can move forward with permitting for a small development plan and not necessarily wait to appraise the entire structure. But we're looking at a few months here before we have news.

Dana Coffield

And then the other part of your question, in terms of joint venture partnerships on exploration blocks, in general, we don't like to necessarily do those 100% so it's quite reasonable to assume that we would, at some point in time, have partners for the exploration program. One of the biggest issues, of course, is not because of the cost of mobilization and logistics, specialty wells, if improved, tend to be very expensive. And upon success, developments tend to be even more expensive. It's appropriate to have partners, particularly substantial partners, to help with that burden. And -- I'm sorry, I was referring to Blocks 107, 133, and then the 2 new Blocks -- not new blocks, but new working interest in 123 and 129. All those 4 blocks I just mentioned now have 100% interest. As you know, Talisman and ConocoPhillips exited 123, 129 for strategic reasons. But now we have a very large, very prospective land position there. And again, it's a high-cost operating environment and partners would probably be appropriate for that.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then just 2 quick additional questions on Colombia. I know you've had a lot of questions on Moqueta, but maybe just to ask it a different way. Can you give us an idea maybe on the upper structure so that the T Sands and the Caballos that were the main target, once your previous enclosure on the structure is assumed and then with the new well, maybe what the enclosure would be? Just trying to get a sense of how big the tank is so far that you've defined. And the second question on Moqueta, just trying to get a sense of kind of where that porosity range is for the net pay that you've mentioned so far.

Dana Coffield

To be honest with you, I don't remember the acres or acreage off the top of my head. I don't remember the acreage. The porosities, they vary from 12% to 22%. What do you think the average is, Shane?

Shane P. O’leary

Oh, probably in that 13%, 15%.

Dana Coffield

13% to 15% average porosity. Again, for the acreage, I don't have the number for acreage for you.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

No problem. I'll follow up off-line. And lastly, just on Turpial. What's the exploration concept there? I know you guys had kind of between 2 bigger heavy oil fields, just trying to get a better sense of what you're potentially chasing on that block?

Dana Coffield

You just said it. There's a -- it's heavy oil clay. It's relatively -- it's poor quality sands and it's in between 2 old, mature, heavy oil fields so we're essentially looking at essentially stratigraphic traps with heavy oil in that. It's not really a key part of our program or focus of our program.

Operator

And gentlemen, your next question will come from the line of John Malone with Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

Just can you give us an update on what's happening on Noroeste, how Proa is holding up?

Shane P. O’leary

Proa, I think it's got about 12% water cut now. I think Proa, too. And it's around 1,200, 1,300 barrels a day.

John Malone - Global Hunter Securities, LLC, Research Division

And you think that's sustainable for the foreseeable future or is it a relatively fast decline? Is that water cut coming up?

Shane P. O’leary

Well, it's come up from 0. Actually, it's 1,400 barrels a day, sorry, just checking the number. So I mean, Proa-1 has been around for quite a while and it's still producing at a pretty good rate. So yes, we've only perforated one zone. There's another zone, too, we can open up at the appropriate time. So it's a pretty prolific well.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And then just going on the answer you gave to George on Moqueta. Just to be clear, you said that figured a few months before you could see any kind of upselling in production in Moqueta. You have to find your oil-water contact, I assume, to kind of get some injection in there. Does that imply that you'll be declining from that sort of 1,000 to 2,000 barrel a day number in Moqueta or do you think you can stay in that range until you get the injectors in?

Dana Coffield

No, we're not -- in fact, we're holding back production right now. So the answer is no, no production decline. And the only thing we need is pressure support in the main field. So it's really the water injection that's holding back production. If we could produce much more now, so we're not -- we're holding back, as I said, because of the pressure support so we're not foreseeing any decline anytime soon in Moqueta.

Shane P. O’leary

We expected more pressure decline than we have seen, which indicates the tank is bigger, which is evident from the wells we're drilling, it keeps getting bigger. So we don't expect -- as Dana said, we don't expect a decline in production.

Operator

And your next question will come from the line of Ian Macqueen with CIBC World Markets.

Ian Macqueen - CIBC World Markets Inc., Research Division

And I've got a few as well. So transportation capacity. I've got a maximum of about 6,500 barrels a day coming out of Moqueta right now. Is there any issue with transportation capacity if Costayaco was online and all the other fields in Costayaco an offsetting area? Plus 6,500, is there any issue with transportation capacity?

Dana Coffield

The -- well, at Moqueta, we're currently cruising recurrently 2,000 to 3000 barrels a day in that range. The capacity, the pipeline from Moqueta to Costayaco is 20,000 barrels per day.

Ian Macqueen - CIBC World Markets Inc., Research Division

Right, but there's a bottleneck down the line.

Dana Coffield

Yes, that's right. No, the bottleneck down the line is on the segment that goes from Santana to Orito and that is full. So that bottleneck is full. So the -- that is the bottleneck. Now the OTA pipeline across the mountains has just been upgraded. They're in the process of testing system. So when I say upgraded, they just created a new pumping station, so there's significant spare capacity in that pipeline imminent. If you've seen Costayaco flat and you assume growing pressure in Moqueta, we would have accommodated that with additional trucking around this, I'll say, 50 kilometer bottleneck between Santana and Orito.

Ian Macqueen - CIBC World Markets Inc., Research Division

And depending on the size of, ultimately, what you think of Moqueta is, you'll address the issue of additional pipeline if you need to?

Dana Coffield

Yes, it's easy to do between the existing pipeline over this 50 kilometer section, use the existing pipeline right-of-way just right along the main highway so it's a very easy thing to do. We investigated this in the past, actually, when we first made the Moqueta discovery. That's always an option to us. It'll probably take about a year to build once we made that decision.

Ian Macqueen - CIBC World Markets Inc., Research Division

And the trucking, because it's 50 kilometers, it's a pretty easy road. It's not a big deal.

Dana Coffield

It's very easy. We're doing that right now, anyway.

Ian Macqueen - CIBC World Markets Inc., Research Division

Yes, okay. So actually, one of the things you said, Dana, during the conversation was 3P of 12 million barrels at Moqueta. That's before royalty number, is it not?

Dana Coffield

That's right, it's 9.8 or 9.9 after royalty.

Ian Macqueen - CIBC World Markets Inc., Research Division

Okay, perfect. Just wanted clarification on that. As far as what you see, obviously, there's faulting within the reservoir at Moqueta. But how do you see reservoir continuity from a reservoir quality perspective? And then obviously, there's discrete zones, is this thickness fairly consistent across the structure?

Dana Coffield

Yes, the thickness of the Caballos and the T Sands is pretty consistent across Moqueta and across the adjacent fields. There is -- there are barriers between a couple of our wells in the Moqueta fields but the main structure, the main block of the reservoir continuity seems to be good. And to south, there's a different fault block. And again, within that fault block, the continuity is good. So there are faults that do break up the overall structure, as we just saw in our last well we drilled. So within each of those fault blocks, the reservoir continuity is good.

Ian Macqueen - CIBC World Markets Inc., Research Division

Okay. So when I'm looking at your map, which is in your presentation, there's the 2 faults to the south and, obviously, you had oil in Moqueta-3 so there is oil to the -- further to the south. Now you've defined oil to the lowest known contour, it looks like about minus 3,500. How deep can you get with Moqueta-8 if you go to the south? Will you go to minus 4,000 and...

Dana Coffield

We won't go -- we're going to try to stay in that same fault block. The purpose of that will be as a producer. So we'll stay in the same fault block where we know there's oil and there's no -- we know there's continuity.

Ian Macqueen - CIBC World Markets Inc., Research Division

You're not -- are you not testing down structure to figure out if...

Dana Coffield

We will be going deeper in that structure.

Ian Macqueen - CIBC World Markets Inc., Research Division

Okay. So there is -- because the way it's drawn, there's a couple of fault blocks, and basically, right -- if you go south of 5, you're in a different fault block, a slightly different fault block.

Dana Coffield

Yes, Shane's getting the presentation for me.

Ian Macqueen - CIBC World Markets Inc., Research Division

I have another question about the lower, the repeat sections. So on the repeat sections, you will get -- you have to still figure out how extensive this is. But at very least, if you test it, you test oil. Those sections are fairly thick. They're 55 feet and 60 feet. GLJ will give you something for it. I would assume they'd give you one spacing unit. Do you know what the spacing unit is for one of those wells?

Dana Coffield

The typical reserves associated with, say, a typical well -- a typical exploration well in this section is around 1 million barrels. Now that will include T and Caballos. So I mean, just very roughly that's over 19. We're getting 2 million, 3 million barrels of reserves in Costayaco, but that's after a long period of production.

Ian Macqueen - CIBC World Markets Inc., Research Division

Sure, sure. So it wouldn't be per zone? I mean, they're thicker zones but it'd be somewhere -- it could be somewhere north of 1 million barrels, I would say.

Dana Coffield

I hate the words in GLJ mouth. But it's something like that. And going back to your first question, yes, I'm not quite sure -- we haven't landed on a definitive Moqueta-8 location, but it's going to be to the left of the 3, I believe. I don't know if it's going to go south of that blue fault.

Ian Macqueen - CIBC World Markets Inc., Research Division

Okay, okay. You'll still get down structure, it looks like, according to that map.

Dana Coffield

Yes, yes, that's correct.

Operator

Gentlemen, your next question comes from the line of Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Two really quick questions for James. Just -- I don't know if you said -- just on hedges. Obviously, you're in an extremely good financial shape. Just your thoughts on hedging going forward.

James Rozon

So currently, at this point, we do not have a strategy for hedging any of our current positions. And again, we're always looking at the options, but currently we do not enter into any hedging transactions.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just one more, just most of the other areas have been hit, just over in Peru on Block 95. Looks like, obviously, historically, there's been pretty good area -- some pretty good results there historically and I assume you're going to spud on that first well, it looks like, here in December. Just your thoughts, Dana, around sort of the potential there or how confident you are in sort of this well or this block?

Dana Coffield

Yes, we're very confident in the well and the prospectivity of the block. We're, I don't know, 1 kilometer or a 1-1/2 kilometers away from a discovery well that flowed 800 barrels a day. We had good quality 2D seismic over it. We've done a contingent resource assessment on the block -- or for this field. And the 1C is 11 million barrels, 2C is 31 million barrels and 3C is 88 million barrels of recoverable oil. And that's contingent resource, and that contingent is contingent upon commercial plat and development of commercial full rates. We know the oil is there. The numbers are huge relative to Gran Tierra's existing reserve base. So the intent of this well is to get good reservoir data, get good quality data and then assuming we get the data to justify it, put together a development plan and have a significant boost in our reserve base there.

Operator

And gentlemen, your next question will come from the line of Brad Virbitsky with Equinox Partners.

Brad Virbitsky

I was wondering if you could go through the sort of -- what sort of return on investment you're looking for in the stuff you're doing now in Brazil and through -- and how that compares to the stuff that you have in Colombia, like Moqueta and Costayaco?

Dana Coffield

The return on investment in those 3 areas is hard to compare because there's such different risks and rewards associated with them. I mean, Peru and Colombia have similar fiscal terms, sliding scale royalties. The royalty rates are a little bit lower in Peru, but the resource potential and the field sizes are so much larger that -- but with a higher risk. So there's a difference in risk and reward between Peru and Colombia where Colombia exploration is at a lower risk but smaller reserve potential. Brazil, again, similar fiscal environment, similar net back, say, to Colombia. But we're planning a new technology and if the technology works, there's a huge resource potential there. So there's not a rate of return number, a single number that we use in our investment decisions. We're looking at different field sizes, different geologic risks, different timing of the first production, that all get layered into it. And it get all -- get layered into making our investment decision.

Brad Virbitsky

So what time frame do you expect to -- in Brazil, in particular, do you expect to, I guess, realize your expectation?

Dana Coffield

Yes, well, we have 2 expectations there, I guess -- well, 3 expectations, if we go back. The first expectation was to develop this existing conventional oil field, which we have now essentially done. So we've grown our production from a couple hundred barrels a day to 1,000 barrels a day. The second expectation is the horizontal drilling campaign that we're about to initiate, and we'll have the first well done before year end and the next 2 horizontal wells testing different sand bodies will be done in the first quarter of next year. So for supplying this new technology in Brazil, we should have answer or have our results by, say, the second quarter of next year. And of course, the third part of our business in Brazil is accessing new land and there'll be a bid round -- there is a bid round scheduled for May of next year. It is our intent to just making that and capture new land.

Brad Virbitsky

Okay. Just one final question. Why do you think your stock is so cheap?

Dana Coffield

For a variety of reasons. First off is it's a risk off, in general, for internationally E&P. So we're in that bucket. Second reason is Colombia, in particular, has been risk off more so than the broader international community for a couple of different reasons. One is delays in permits, environmental permits. There's also been -- smaller field sizes have been discovered recently that had been expected by the investment community. And the third reason is there's increased security events, bombings of infrastructure, in the first half of this year. So Gran Tierra was hit by all of those. So I think that's why we're trading where we are. It's clear, in my own mind, that we're undervalued today and there's huge potential that we're delivering every quarter with new oil reserves and production. And it's just going to take the market time to sort itself out with Europe, with Colombia and with our continued success.

Operator

And gentlemen, your next question will come from the line of Jamie Somerville with TD Securities.

Jamie Somerville - TD Securities Equity Research

A lot of good questions, which gets me thinking and let me just at least one follow-up question. Dana, on the forecast that you'll have an environmental permit for the middle of next year for the whole Moqueta, can you just say how you do that forecast? Because most people in Colombia, when they make a forecast of that type, it ends up being wrong. And can you say when the application for that environmental permit actually went in?

Dana Coffield

Within the last -- well, 3 months ago and I'm assuming it's going to take about a year. So that takes me to the middle -- I mean, it should be -- in theory, it should be faster so I put some slippage time in there because of the delays the issuing environment has had.

Jamie Somerville - TD Securities Equity Research

You're just basing on kind of what you think the average for that type of permit application is at this point in time.

Dana Coffield

That's correct.

Jamie Somerville - TD Securities Equity Research

Okay, perfect. And then on the expansion that's being done on the OTA pipeline, can you kind of put some numbers around that from where the capacity might be going to and from and why Ecopetrol would have decided to do that expansion? Is that to accommodate your production? Or where is that production growth in the Putumayo Basin?

Dana Coffield

Yes, it's a good question. The first phase, what they've done is they've rebuilt a pumping station up in the mountains. The first stage of the capacity expansion is to increase to 65,000 barrels a day from its current, I guess, 45,000 barrels a day. And then I believe, ultimately, was more bottlenecking. They can get it up to 85,000 barrels a day is a plan. And it's part of a broader strategy of increasing capacity for transtation [ph] capacity in the countrywide. And they're also doing the same to put the mile for the pipeline going south into Ecuador. I don't think, today, there is the backup reserves or production -- backup production to fill these lines. I think they're staying ahead of the game and building that capacity for expected increase in production.

Jamie Somerville - TD Securities Equity Research

And in the short term, if there are outages, it increases the potential for you to ship backed up volumes out of the basin if there are further line disruptions.

Dana Coffield

That's exactly -- that is -- the other reason is when the pipelines are working, they can put more throughput through the line than had been in storage, so that helps evacuate oil out of the basin during the -- or after the downtime.

Operator

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

Dana Coffield

All right. Well, thank you, everyone. I'd like to thank everyone for joining us today, and we look forward to speaking with you next quarter to update you on our progress. Thanks for your attention.

Operator

Ladies and gentlemen, we thank you for your participation in today's conference. This does conclude that the presentation, and you may now disconnect. Have a wonderful day.

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