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Gran Tierra Energy (NYSEMKT:GTE)

Q4 2012 Earnings Call

February 26, 2013 4:00 pm ET

Executives

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

James Rozon - Chief Financial Officer and Principal Accounting Officer

Shane P. O’leary - Chief Operating Officer

Analysts

John Malone - Global Hunter Securities, LLC, Research Division

George Toriola - UBS Investment Bank, Research Division

David Popowich - Macquarie Research

Hubert van der Heijden

Justin Anderson - Salman Partners Inc., Research Division

Christopher Beer - RBC Capital Markets, LLC, Research Division

Caio M. Carvalhal - JP Morgan Chase & Co, Research Division

David Neuhauser

Michael Letros

Operator

Good afternoon, ladies and gentlemen, and welcome to the Gran Tierra Energy's Results Conference Call for the quarter and year ended December 31, 2012. My name is Lisa, and I'll be your coordinator for today. [Operator Instructions] I would also like to remind everyone that this conference is being webcast and recorded today, Tuesday, February 26, 2013, at 4:00 p.m. Eastern Standard Time.

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

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

Listeners are urged to carefully review and consider the various disclosures made by Gran Tierra Energy in its reports filed with the Securities and Exchange Commission, including those risks set forth in Gran Tierra Energy’s annual report on Form 10-K for the year ended December 31, 2012, filed with the Securities and Exchange Commission, February 26, 2013.

If one or more of these risks or uncertainties materialize or if 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 it's available on Gran Tierra Energy's website, www.grantierra.com. All dollar amounts mentioned in today’s conference call are in U.S. dollars, unless otherwise stated.

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

I will now turn the conference over to Dana Coffield, President and Chief Financial Officer of Gran Tierra Energy. Mr. Coffield, please proceed. Thank you.

Dana Coffield

All right. Thank you, Lisa. Good afternoon. Thank you for joining us for Gran Tierra Energy's Fourth Quarter and Fiscal Year End 2012 Results Conference Call. With me today is Shane O'leary, our Chief Operating Officer; and James Rozon, our Chief Financial Officer.

Earlier today, we disseminated a press release that included detailed financial information about the quarter and full year 2012. In addition, Gran Tierra Energy's 2012 report on Form 10-K for the year ended December 31, 2012, has been filed on EDGAR and is available on our website at www.grantierra.com.

I'm going to begin today by talking about some of the key developments for the fourth quarter and year. James will then take a few minutes to discuss key aspects of the year's financial results. Shane will then provide an operational review and outlook, followed by my closing remarks.

Gran Tierra Energy achieved annual production in 2012 of 16,897 barrels of oil equivalent per day, net after royalty and after inventory changes, representing a 3% decrease from the average 2011 production. This decrease was due to unanticipated increase in disruptions on the Trans Andean, or OTA, pipeline in Colombia. Mitigation plans for disruptions were developed and implemented over the second half of last year. These are now fully operational and we are producing at near-record levels of approximately 21,000 barrels of oil equivalent per day net after royalty for the first 2 months of this year.

Reserve growth last year was outstanding, not only replacing production but substantially adding new reserves. Based on Gran Tierra Energy's 2012 year end SEC reserve calculations, total crude net after royalty reserves increased 19% to approximately 40.6 million barrels of oil equivalent. Total crude plus probable reserves net after royalty increased 15% to approximately 56.2 million barrels of oil equivalent, and total crude plus probable plus possible reserves net after royalty increased 1% to approximately 86.3 million barrels of oil equivalent.

Now importantly, the weighting of oil versus gas increased in all 3 categories to 95% for 1P, 95% for 2P and 87% for 3P. All of this oil is light and medium-grade -- sorry, medium crude with no heavy oil in the reserves. Equally important, based on these reserves in Gran Tierra Energy's 2012 total working interest production, Gran Tierra Energy's 1P, 2P and 3P reserve life indices grew to 6.4 years, 8.9 years and 13.6 years, respectively.

We also added significant to landholdings in our core areas of operations in 2012. Gran Tierra Energy was the successful bidder on Sinu-1 and Sinu-3 blocks in the Sinu Basin of Northern Colombia in an ANH 2012 bid round. In addition, working interest in Blocks 129, 142, 155 and 244 in Brazil increased to 100% working interest, and Block 95 in Peru working interest increased to 100%, and working interest in Blocks 123 and 129 in Peru increased to 100% also, the latter still being subject to government approval.

In addition to our operational success, our balance sheet remains strong. Funds flow from operations was a record $323.8 million. Cash and cash equivalents were $212.6 million at December 31, 2012. We remain debt-free.

Looking forward to 2013, we are expecting this year's capital program to be funded from cash and cash flow from operations at current oil prices and production levels with potential periodic withdrawals on our credit facility, if needed.

2012 was an excellent year. Needless to say, 2013 is off to an extraordinary start. But before addressing that, let me now turn the call over to James Rozon to discuss our 2012 financial results. James?

James Rozon

Thank you, Dana, and good afternoon, everyone. Our operational success last year has also translated into another year of financial success. We have retained a strong balance sheet to continue funding our growth strategy.

Revenue and other income in 2012 was $585.2 million, a 2% decrease from 2011 due to decreased production, partially offset by increased average realized oil prices. The average price received per barrel of oil increased by 1% to $97.31 from $96.60 from 2011.

Operating expense in 2012 were $124.9 million or $20.20 per BOE, compared with $86.5 million or $13.61 per BOE in 2011. The increase in operating expense was mainly due to an increase of $29.3 million in Colombia, which was the result of a change in sales point in February 2012 and increased trucking costs to other sales points due to pipeline disruptions. The sales point for our oil sold to Ecopetrol changed from the entry of the OTA pipeline to the end of the pipeline at the Port of Tumaco. Transportation costs previously netted from the sales price are now included as operating costs as we retain title of the oil until the Port of Tumaco.

Depletion, depreciation, accretion and impairment, or DD&A, expenses in 2012 were $182 million compared with $231.2 million in 2011. DD&A expenses in 2012 included a $20.2 million ceiling test impairment in our Brazil cost center related to seismic and drilling costs in the BM-CAL-10. DD&A expenses in 2011 included a $42 million ceiling test impairment in our Peru cost center related to drilling cost from a dry well and seismic costs on relinquished blocks.

Also included in 2011 was a $25.7 million ceiling test impairment loss in our Argentina cost center related to an increase in estimated future operating and capital costs and a decrease in reserve volumes. On a per BOE basis, DD&A expenses in 2012 were $29.44 compared with $36.39 in 2011, representing a 19% decrease. The decrease was mainly due to lower impairment charges of $3.42 per BOE in 2012 compared with $10.65 per BOE in 2011.

General and administrative, or G&A, expense decreased by 2% to $58.9 million, primarily due to increased recoveries, increased capitalized cost in Peru and the absence of expenses related to the 2011 Petrolifera acquisition. These G&A expense reductions were partially offset by increased employee-related costs and bank fees relating to expanded operations. G&A expenses per BOE were $9.52 and were comparable with 2011.

Other gain of $9.3 million in 2012 relates to a value-added tax recovery. This gain resulted from the completion of a reorganization of companies and their branches in the Colombian reporting segment during the fourth quarter of 2012. Included in 2012 results is a foreign exchange loss of $31 million, which included an unrealized foreign exchange loss of $17.1 million. This unrealized loss was due to the strengthening of the Colombian peso against the U.S. dollar and included the translation of current and deferred tax liabilities denominated in Colombian pesos. The realized foreign exchange loss in 2012 primarily arose upon payment of 2011 Colombian income tax liabilities.

Gran Tierra Energy had net income of 2012 of $99.7 million, compared with $126.9 million in 2011. In 2012, Gran Tierra showed decrease DD&A, G&A and income tax expenses, the realization of a gain upon a corporate reorganization in Colombia and the absence of a Colombian equity tax expense. These amounts were more than offset by a decreased oil and natural gas sales, increased operating expenses and foreign exchange losses and the absence of the 2011 gain on acquisition.

Funds flow from operations increased by 1% to $323.8 million in 2012 from $319 million in 2011. The increase was primarily due to lower income tax expenses being partially offset by increased operating expenses and realized foreign exchange losses. A reconciliation of net income is included in our 2012 earnings press release.

Cash and cash equivalents were $212 million at December 31, 2012, compared with $351.7 million at December 31, 2011. A change in cash and cash equivalents during 2012 was primarily the result of funds flow from operations of $323.8 million and an $11.9 million decrease in restricted cash and proceeds from issuance of common stock of $4.3 million. These inflows were more than offset by capital expenditures of $276.1 million and net increase in assets and liabilities from operating activities of $167.4 million and cash paid for an acquisition in Brazil of $35.5 million.

In summary, Gran Tierra Energy remains financially strong. We expect that our 2013 capital program of $363 million is to be funded from cash flow from operations, cash on hand and potential periodic draws from our revolving credit facility, if needed.

That concludes my comments. I would now like to turn the call to Shane for an update of Gran Tierra Energy's 2013 capital plan and outlook.

Shane P. O’leary

Thank you, James. Colombian production averaged 13,146 barrels of oil equivalent a day in 2012 net after royalties. Production for 2012 was below target due to unanticipated increase in pipeline disruptions in Colombia, particularly on the Ecopetrol-operated OTA pipeline. As Dana mentioned, alternative transportation measures have been put in place to mitigate future disruptions and are now fully operational and working.

In 2012, Gran Tierra focused on further delineation of the Moqueta field and maintaining production in the Costayaco field. Gran Tierra Energy completed testing of Moqueta-7 in the third quarter of 2012 and has since collected reservoir data and fluid samples from the reservoirs in 3 repeated fault blocks. Subsequent to year end, Gran Tierra announced a flow rate of 1,146 barrels of oil per day from the well.

Moqueta-8 reached total depth prior to year end and completed testing subsequent to year end at an initial oil test rate of 1,600 barrels of oil per day. Moqueta-8 is currently on production. To further define the reserve potential of the field, we spud Moqueta-9 on January 20, 2013, targeting the northern portion of the field. Drilling of this well is ongoing.

Appraisal drilling in the Moqueta field resulted in 1P reserves increasing 45% to approximately 8.7 million barrels of oil, 2P reserves increasing 54% to 14.9 million barrels of oil and 3P reserves increasing 108% to 26.9 million barrels of oil on a company-interest basis. This is tremendous growth over the previous year and Moqueta discovery will play a large part in growing production for the company. It is important to remember, we have not yet defined the lateral extent of the oilfield nor the depth to which the oil column extends. Additional upside remains in this growing field.

Moving on to Costayaco. Superior reservoir management and performance resulted in a significant increase in the field's reserve base in 2012. 1P reserves increased 20% to 19.7 million barrels of oil, 2P reserves increased 29% to 23.5 million barrels of oil and 3P reserves increased 12% to 26.1 million barrels of oil net after royalty from year end 2011 reserves, respectively. Costayaco remains our core asset, funding of the development of Moqueta and our other growth programs in the company.

We made a new oil discovery in Colombia last year, together with our partner, with the Ramiriqui-1 oil exploration well. The long-term tests for Ramiriqui-1 is expected to begin in April. We are evaluating options for testing additional reservoir intervals by drilling another well on the block later this year.

Moving to Peru. In December 2012, we started drilling the Bretaña Norte 95-2-1 XD exploration well on Block 95 and reached true vertical depth of 8,851 feet earlier this month. Initial drilling results indicate an all saturated reservoir with a gross oil column of 99 feet. Late last week, we announced production test rates of 1,984 barrels of oil per day of 18.5-degree API oil, a result that far exceeded our expectations. We are currently evaluating full-field development options and anticipate first long-term test production from the Bretaña field within the next 12 months.

This field has a very material contingent resources booked to it, part of the drilling of this well. Our intent is now to prove commerciality and begin the process of booking the substantial reserve potential of the field. Brazil production averaged 277 barrels of oil per day in 2012 net after royalties.

In 2012, production was initiated under a flurrying [ph] restriction from 2 wells drilled at the Tiê field on Block 155 with current production at approximately 1,000 barrels of oil per day gross or 850 barrels of oil per day net after royalty. Once natural gas could be tied into the Petrobras gas infrastructure, we can expect production to increase to approximately 2,000 barrels of oil per day gross. We have drilled 2 horizontal wells in Brazil, one -- with one more planned later this year. Multi-staged fracture stimulation operations have been initiated. We are expecting results from our horizontal well program in the second quarter of 2013.

Argentina production averaged 3,474 barrels of oil equivalent a day in 2012 net after royalties. In 2012, we continue to focus on developing our producing fields, including the Surubi and Puesto Morales fields. We successfully drilled and tested the Proa-2 appraisal well, which tested 6,300 barrels of oil per day of 46 API gravity crude oil. The Proa-2 well was put on production in April.

In the Puesto Morales block, we drilled the PMN-1117 well, the first horizontal multi-staged fracture stimulated well in the tight sands of the Loma Montosa formation. This well is currently flowing naturally at a choke-restricted rate of 100 barrels of oil per day of 33.8 API oil with a 27% water cut. We're adjusting our work program to further evaluate this new play with additional drilling.

Looking forward in 2013, Gran Tierra Energy anticipates spending $363 million on exploration and development opportunities, allocating $224 million to Colombia, $38 million to Peru, $67 million to Brazil and $31 million to Argentina. Gran Tierra Energy's Colombian program includes drilling 4 gross exploration wells and 6 gross appraisal and development wells, as well as a 3D and 2D seismic acquisitions, which are leads and prospects for drilling in 2013 and beyond.

Gran Tierra Energy anticipates spending $119 million on drilling activities and $66 million on G&G. And in addition to the above exploration activity, we plan to spend approximately $39 million on facilities work. The Peru budget of $38 million includes drilling the Bretaña Norte 95-2-1 XD exploration well on Block 95, which was recently completed. Approximately $21 million is budgeted for drilling costs and $17 million is budgeted for seismic acquisition and facilities costs.

With our recent testing success, we anticipate adding approximately $16 million to drill a horizontal sidetrack, complete the sidetrack and build facilities for barge crude oil loading. The $67 million capital program in Brazil includes $43 million budgeted for drilling, $18 million for facilities and pipelines and $6 million for G&G expenditures.

Gran Tierra Energy plans to drill 2 gross horizontal exploration wells in the Recôncavo Basin, along with additional completion work on producing wells in the Tiê field. Brazil's exploration program could increase to 6 total exploration wells in 2013 if the onshore resource play concept is tested successfully with our initial horizontal drilling program. Gran Tierra Energy is planning to participate in the upcoming ANP bid round in May in onshore areas, and we will be evaluating the data packages when available.

Our planned work program for Argentina in 2013 includes drilling 1 gross exploration well, 4 gross development wells and 1 gross appraisal well. In addition, we are planning to conduct 7 workovers and 3 conversion projects to change producing wells into water injection wells. Our focus is to grow production from our existing assets. Of the $31 million capital budget for Argentina, $19 million will be spent on drilling.

Excluding potential exploration success, production in 2013 is expected to average 27,000 barrels of oil equivalent per day, appropriately [ph] working interest with no pipeline disruptions. Assuming a 10% contingency for potential disruptions and a $90 average price for Brent, production is expected to average approximately 20,000 barrels of oil equivalent per day net after royalty and before inventory adjustments.

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

Dana Coffield

All right. Thank you, Shane. So Gran Tierra Energy had an excellent year last year and a substantially strong growth as a company today than it has ever been. Reserves and reserve life indices are larger than ever. Light and medium-crude oil weightings are greater than they have ever been. Production capacity is at record levels and actual production in the last 2 months is near record levels.

Our balance sheet remains solid, with this year's capital program fully funded from cash and cash flow from operations at current oil prices and production levels with potential periodic draws on the credit facility, if necessary.

Perhaps our greatest strength today is the visible growth that is now contained in our assets without additional exploration success. Costayaco in Colombia remains our key asset with our base of reserves and production. But now, with continuing appraisal success at the nearby Moqueta, we can see very clearly continued growth in the near term above and beyond Costayaco. Most recently, with our discovery in Peru, we are beginning to get visibility into our midterm growth above and beyond Moqueta and in a geographically independent location.

The talented, experienced and proven operating teams in every one of our countries of operations are perfectly positioned to continue executing on our proven growth strategy. We are extremely excited about the future of the company. We'd like to thank all of our stakeholders for their continued support of Gran Tierra Energy in this endeavor.

Now that concludes our prepared comments for this morning, or this afternoon. We would now be pleased to answer any questions you may have. So back to you, Lisa.

Question-and-Answer Session

Operator

[Operator Instructions] Okay. So our first question comes from the line of Mr. John Malone, Global Hunter Securities.

John Malone - Global Hunter Securities, LLC, Research Division

Dana, a question on Brazil. What do you think you'd need to see from the first 3 wells there to justify the additional wells that you talked about? And when would the extra CapEx draw [ph] be for those additional wells or is that already baked into the $67 million?

Dana Coffield

No, what we're doing with those 3 horizontal wells is drilling 3 different independent reservoir targets. What we're trying from the 3 wells is a feel for the variation, reservoir quality and productivity with the different fracture stimulations. On an ideal situation, we'd get, call it 500 barrels a day, 300 barrels a day as a sort of a low-end production rate. It's important to remember, these are the first horizontal multi-staged fracture stimulated wells ever drilled in an entire country. So it's going to take time to learn how the reservoir performs, how the fracture stimulation works with the optimism -- what the optimum spread is. So it's going to time, but if we can get sustained flow of hydrocarbons, that's going to give us the confidence to continue drilling additional horizontal wells. Now those additional horizontal wells are not part of our current existing budget, because that would have to come from our remaining cash balance at that time.

John Malone - Global Hunter Securities, LLC, Research Division

And if you get those kind of rates, then what do you think the total number of locations would be that would be drillable across your acreage in Brazil?

Dana Coffield

It's -- again, it's hard to give a firm number, but there's easily 40 locations. It just depends on the recovery we're seeing per well. But there's a substantial running room of multiple years of drilling ahead of us if it works.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And then just on Peru, on Bretaña, what steps need to be taken before you can actually book those reserves? What has to happen?

Dana Coffield

Specifically, we need to have a commercial development plan that is approved by the board, the Board of Directors, like an early or first stage development plan that's commercial and approved by the Board of Directors. With that as a commitment to move forward with a development, that should be enough for our independent reserve engineers to test reserves based on the wells.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And then for permitting from the government and for actual commercial development, what needs to happen?

Dana Coffield

We have a base permit now. There's -- there will be multiple additional permits required before there's a government-sanctioned commercial development, so we'll need an additional permits for drilling, we'll need permits for water disposal, we'll need permits for transportation, crude oil transportation. There's a lot of work ahead of us before we get a government-sanctioned full-field development plan done. That's separate from this long term test, which we already have permitted. We still need to go through the contracting for the barges and crude oil sales and such. So we expect the long-term test to begin within the year. But full-field commercial development plan approved by the government will take some time.

Operator

Our next question is from Mr. George Toriola of UBS.

George Toriola - UBS Investment Bank, Research Division

So my question is on Peru. So the well you talk about, you talk about rising pressures while you were testing 2 [ph] that the -- there was still cleanup going on, but you proceeding with a horizontal well there. So I'm just wondering if you can talk about what's the motivation for that? Is that drawdown as you see? And then what does that say about productivity or there's something else that's behind that?

Dana Coffield

No. The reservoir was still cleaning up in the short-term test that we conducted, but we had to suspend the test because our storage capacity for the fused [ph] oil has been reached, which was 2,000 barrels gross storage capacity. So what we want to do is continue understanding the reservoir, so we're extending this well by drilling a horizontal sidetrack at the top of the reservoir. The reason for the drilling a horizontal well is because of the extremely high-quality reservoir. It's very high porosity, very high permeability. We want to maximize the standoff from the well bore from the underlying water column to minimize the drawdown. This is standard practice in this basin, in this reservoir as shown by the -- or as done by the -- as experienced by the other operators in the basin. They've learned by filling horizontals at the top of the reservoir, you minimize drawdown, you minimize water breakthrough, you maximize oil recovery. So we're doing this in part based on the learnings and experiences of other operators in the basin.

George Toriola - UBS Investment Bank, Research Division

Okay. And sort of where is this, how long is your horizontal leg going to be in and sort of how much of the reservoir are you appraising with this horizontal here?

Dana Coffield

It's a 500-meter horizontal leg. The well is located -- it's a north-south sort of elongated shape structure. So the well, this horizontal leg will be about 1/3 of the way down or south along the structure. So it will be -- it's going to be close -- it will be centrally located in the field, if that's what you're asking.

George Toriola - UBS Investment Bank, Research Division

Okay. What about deep? Does it -- does the -- is it -- what sort of deep change do you have across that?

Dana Coffield

It will be essentially flat for both the reservoir and the wellbore, within a couple degree dips [ph].

George Toriola - UBS Investment Bank, Research Division

Okay. And just quickly on Moqueta. What -- when you -- when we look at the entire field, just based on everything you know now, what still stands of the -- the repeated Caballos that you found, I think was on Moqueta-7, I believe it was. What's your sense of the occurrence of that? How local is it or how regional is that, that bolt in and [indiscernible]?

Dana Coffield

I would expect it to be common, that repeat session be common around the southern, western and eastern flanks of the structure. To the north, you have -- based on uplift, the mountain uplift and there may be some potential repeated section under that as well, which we're going to evaluate over the future drilling campaigns. So I think when we have this major fault that's created in the Moqueta field, the Moqueta structure, there's this potential for repeated sections around the flank of the field. So not over the entire field, but around the flanks.

George Toriola - UBS Investment Bank, Research Division

That's right. So, okay. That's helpful. And so post Moqueta-9, after Moqueta-9, where would the next well in that field be?

Dana Coffield

We're planning on Moqueta-10 right now and it will be on the southern side of the field.

George Toriola - UBS Investment Bank, Research Division

Okay. Around the flanks?

Dana Coffield

Correct. Let me just -- let me make one more comment, too. When we're talking about the field in this drilling, we're really limited to drilling central and western portion of the entire structure. We don't yet have permits or able to access the eastern flank of the structure, so the whole portion of the Moqueta structure that has not yet been drilled. You have to keep that in mind also when we talk about the field. We don't yet know the lateral extent of this field.

George Toriola - UBS Investment Bank, Research Division

And well, what's the status with that permit? When do you think you'd have that?

Dana Coffield

The permit is under review and we hope to get it -- that by the end of the year.

Operator

Our next question is from the line of Mr. David Popowich of Macquarie.

David Popowich - Macquarie Research

I just wanted to follow-up on the Brazil question. I see that you're in the second exploration phase for the 4 Recôncavo blocks and that expires at the end of this year. So was just wondering what are the implications of that if you guys don't drill a well on one of those blocks?

Dana Coffield

Well, if we don't do any work on the blocks, then they will get relinquished. So we're doing work on it.

David Popowich - Macquarie Research

Relinquished entirely?

Dana Coffield

Yes. But we are doing work on them.

David Popowich - Macquarie Research

All right. And then I also wanted to know how I should think about first quarter sales volumes. I mean, I see that the OTA was down again for most of January and February, so your production volumes are doing very well but what kind of inventory builds do you think we should be expecting in the first quarter?

Dana Coffield

We don't, at this moment, have significant inventory builds other than what's originally in the pipelines and such. So I think our -- well, our sales should be stronger this quarter. I don't know if, James, you want to make...

James Rozon

Yes. Again, in terms of inventory, we'd have to look to see what happens later in the quarter in terms of other issues that may prevent us from delivering through various sales points. So again, right now, we've been able to decrease our inventory since yearend just by continuing to track out of our inventory, more specifically. Now again, we sell to a third-party in which it takes some time for them to actually deliver that oil to market and sometimes the inventory builds. So it just depends on the timing of when we sell to that third party.

Operator

Our next question is from the line of Mr. Hubert van der Heijden, Tudor, Pickering and Holt.

Hubert van der Heijden

So obviously, it sounded like the reservoir quality at Bretaña was significantly better than expected and so was the deliverability seen today. Can you talk a bit and maybe put some numbers around the porosity and permeability and how does that compare to the pre-drill expectations?

Dana Coffield

Let's see, well, the porosity's in, I guess, the low 20...

Shane P. O’leary

20s

Dana Coffield

20%. 20% to 25%. The permeabilities are in excess...

Shane P. O’leary

Multi-Darcy.

Dana Coffield

Yes. Excess of Darcy, multi-Darcy. So it's -- and it's a clean medium [indiscernible] quart sandstone, no clays of note. So it's a -- just a world-class reservoir, very high quality.

Hubert van der Heijden

Okay. So, and I guess what kind of -- or maybe it's still a little bit early to think too much about that, but how are you thinking about recovery factor ranges at this point?

Dana Coffield

I guess I don't have a recovery factor in mind, it's a -- well, I don't know.

Shane P. O’leary

Well, I mean, that's what the long-term test is going to help us define, get us a lot more reservoir information, help us understand the commercial contracts we have to get into, the pricing of oil. And by the way, we expect to make money on this long-term test above and beyond the cost of the well, so we're not doing this purely for information. But we -- that's the type of information that we'll be able to get a better handle on. But, I don't know. Just off the top of my head, I would say 20% in excess of it now at this point. But in terms of what reserve potential is, you have the contingent resource numbers, the GLJ provided and those are pretty good indications of the recoverable reserves' potential for the field.

Hubert van der Heijden

Okay. Perfect. And then last question on Bretaña, just on when doing the horizontal test, is that purely something to reduce potential water coning or preferential water production? Or are you also expecting to see a decent horizontal uplift in terms of delivery rates on a per well basis?

Dana Coffield

Well, the answer is yes to both of those. It will minimize coning of the water, and it will increase the production rates, the tests in a vertical well bore over 27- and 29-foot section was 2,000 barrels a day. This horizontal well will have a much longer or much greater exposed reservoir phase, so we'll have higher production rates from the horizontal well. Again, we don't know what the optimum rate is but we will get higher rates and we will minimize water breakthrough through the coning that you mentioned.

Operator

Our next question is from Mr. Justin Anderson of Salman Partners.

Justin Anderson - Salman Partners Inc., Research Division

So we've seen steady a increase in 2P reserves at Costayaco and Moqueta over the years, and I just was wondering if you guys could take a moment and comment on what's primarily driven that. And talking about the reserve report and how the engineers are looking at this, are they using volumetrics, primarily a decline analysis mass balance? Just give us a sense of -- these are pretty big increases, especially at Costayaco relative to the age of the field and it'd be great to get a better understanding of how this caught the engineers so blindly.

Shane P. O’leary

A big factor was that the water saturation throughout the reservoir was much lower than what was originally thought by the reserve auditor. We did have core analysis several years ago that indicated it was quite low, but they wanted to have some production history before accepting that information. So over the course of a year or 2, they were convinced that the water saturation was much lower just because of the way the wells were producing in the low water cuts. And I would have to say that, that was one of the biggest factors that's led to an increase in reserves and technical adjustments upward over time. There has been some structural increases. I mean I wouldn't say that's the major thing, I'd say it's majorly water saturation. The other thing is the waterflood is incredibly efficient. It's being injected into the aquifer zones of the natural aquifers and we're currently able to inject about 23,000 barrels a day, which is about -- it's pretty close to what we're taking out, so we're actually maintaining pressure and the plan over the course of this year is to increase that 23,000 injected water to 40,000. We're actually pressuring up the reservoir, increasing pressure at this point. So -- and it's just the sweep efficiency of the waterflood, just the nature of the way the reservoir is laid out going some form of vertical. The vertical nature of it, it's like a piston drive from the lower part of the reservoir, up to the top where the producing wells are. And it's increasing the recovery factors to top decile type performance for these types of reservoirs. So I think, overall, those are the 2 things.

Dana Coffield

And then the answer to the question on Moqueta side is we're physically stepping out, finding new rock volume and new reserves in the new rock volume. So right now, Moqueta is a different story for the reserve growth. We're physically finding additional rock volume with reserves and we're continuing that process. We have not yet found the limits of that field.

Operator

Our next question is from Mr. Chris Beer of RBC Asset Management.

Christopher Beer - RBC Capital Markets, LLC, Research Division

Just wondering if you can shed some light on the long-term test at Bretaña? Like what is required there? You would have to, I guess, barge a lot of equipment and tanks to the site, and is that the main and do you need permits for that? Or -- so time -- some timing on that, and I guess what would be the size of tanks that you would have to have and how long would a test go on for?

Dana Coffield

Yes. Everything at the Bretaña location is brought in by barge. It's -- in this part of Peru and Amazon basin, the river systems are the road system. So everything done to date has been brought in by barge. The location is just right off the river, so just a couple of hundred meters away. So -- and then people are brought back and forth either by boat or by aircraft with the floats laying on river in front of the village there. So the logistics, that's -- all the equipment will have to be brought in by barge and the intent is, of course, to get this done, equipment in place and long-term test started within the year. The -- I don't have -- we don't yet have designed the size of storage that's required, so that's a work in progress. We don't have a number to give you. I think the other part of your question was how long will the test take. The test would be a 6-month test, and then we have an option to extend that test for another 6 months. So it could be for up to 1 year and it fits [ph] the other parts of your question.

Operator

Our next question is from the line of Mr. Caio Carvalhal of JPMorgan.

Caio M. Carvalhal - JP Morgan Chase & Co, Research Division

I have a question in relation to the cost increase and how can we see it going forward. We note that the average in 2012 was a OpEx per barrel at about $20, increasing to $23 by the 4Q. I understand that part of this increase was related to the decline in production. But my question would be, if we look to 2013, I assume that the increase in production should have a positive effect on that cost but at the same time, a higher volumes of '13 should offset part of this gain if not is an increase there. So my question would be, looking to this level of $20 to $23 operational cost in 2012, how should we view 2013? Should it increase or be at more or less the same level?

James Rozon

So I'll answer that question. So our 2013 operating cost estimate per barrel would be approximately $22 a barrel based on the production guidance that we gave for 2013. So we're not really looking at a significant increase. That number includes a contingent downtime factor related to Putumayo Basin production, should the OTA go down. So that would include then obviously increased trucking costs for that downtime.

Caio M. Carvalhal - JP Morgan Chase & Co, Research Division

And this expected increase in production costs is already considered in this expectation of $23 per barrel? That's what I -- I understood it correctly?

James Rozon

Yes, except for, again, we have changing transportation contracts or sales contracts, so those could change and it depends where we deliver our oil to.

Operator

[Operator Instructions] We have one more question, sorry, it's from the line of Mr. David Neuhauser of Livermore Partners.

David Neuhauser

Obviously, it looks like you guys are doing a number of things that are definitely helping the equity at this point. My real question was, I know earlier in the quarter, we had a little bit of a scare regarding rumored royalty changes in Columbia. I want to see if you could comment on that at all.

Dana Coffield

Well, rumors in general, we don't comment on but I have no knowledge whatsoever of any royalty changes in Columbia. I would be, at least, on a retroactive basis, I would be -- I just don't see that as being possible to retroactively change royalties in Columbia, so I think that's a spurious rumor.

David Neuhauser

Yes. I -- again, I heard that and I think that was part of the weakness earlier in the quarter and a bunch of different Columbian equity names, but of course since has subsided. I guess my issue is whether or not that seems to be something that could actually take place with the government at this point in time, is that essentially -- could it materialize at all?

Dana Coffield

No. The -- there was a change in taxes earlier in -- this year in Columbia, some new tax legislation. Now there is a royalty dispute, maybe this is what you're referring to. It's high price -- it's called high price royalty dispute that we have and a couple of other companies have, [indiscernible], and it's the interpretation of how the high priced royalties are applied. So that may be -- and that's previously disclosed by all companies. That might be what you're referring to. In terms of the change in royalties, I just don't see that happening in Columbia.

David Neuhauser

Okay. Yes, that's exactly what I think we were describing. I think that was sort of the fear recently on those -- the potential change here. Given Columbia to date, how are you guys looking at the country at this point in time in terms of opportunities? Or are you guys becoming much more focused on different areas and different geographies such as Peru and making a bigger foothold in Brazil?

Dana Coffield

No. We're very much focused on new ventures in Columbia, as well as Peru and Brazil. So we have new ventures teams looking at new opportunities all the time in Columbia, as well as Peru and Brazil. In fact, we just participated in a big round in Columbia and won 2 new blocks. There's numerous farm in, farm out type deals on the market now. There's a variety of asset acquisition divestiture opportunities. So we're looking at all of them. We're finding it hard or difficult to find opportunities that are material to Gran Tierra and have real value creation potential for Gran Tierra, so we're in this, I'll call it a luxurious position where we can grow on our existing lands comfortably in the coming years. So for something new to come into our portfolio, it has to be very compelling. We don't need to do acquisitions to grow. We're looking at them as just a normal course of business in maturing our portfolio, but we don't have to do them. We're comfortable with being patient.

David Neuhauser

Are some of the smaller companies out there that you would normally look at as being maybe targets, such as the one you guys have acquired in the last several quarters, I mean, are they becoming more targets based on some weakness in the equity prices at this point? Or are they risk reward not essentially there for you guys at this point? Are you seeing more opportunities or less?

Dana Coffield

I'd say -- I want to say more opportunities, but there's still quite a few opportunities. So it's not less, there's a steady flow of opportunities. You sort of touched on the challenge, is the smaller ones tend to have smaller prospects on them, not a lot of running room. They're sort of scattered blocks throughout the country, so it's difficult to find any that are material to Gran Tierra or any that Gran Tierra could actually create value from. I think they tend to be challenged for a variety of other reasons. So their share price, it may be down but that doesn't help us in growing our business. We need materiality, we need synergy with our existing operations and we need to see growth potential that is impactful to Gran Tierra.

David Neuhauser

Okay. And lastly, Dana, I mean, given all the things we just described, I mean, the reserves increasing, production increasing, getting to record levels on some things and having sort of the balance sheet you have, still, the equity price is somewhat languishing. It looks extremely undervalued, at least in my opinion. Is the board looking at that avenue and seeing any other potential ways of extracting further value for shareholders at this point? Or is it sort of a wait-and-see approach and see some of the further well test down the road?

Dana Coffield

Well, no, it's definitely not a wait-and-see approach. We're going to continue doing exactly what we've done for 8 years now and that's pick up land, identify prospects to drill, drill them, find reserves, grow production and grow cash flow. The weakness in share price that we're experiencing is shared by all our peers and that's a risk -- due to the risk aversion in the market driven by Greece, and -- today, I believe it's driven by Italy elections. We're not going to change our growth strategy that's been so successful over the last 8 years. The markets are going to ebb and flow. We can't influence that. We can influence our growth strategy by executing on budget and on time, and we've been very successful with that and that's our plan going forward.

Operator

Our next question is from Mr. Michael Letros with Libra Advisors.

Michael Letros

I think one of the overlooked factors behind GTE is really how modest your future development costs are. And I think looking at the report that was issued today, on a 2P basis, it's around $355 million. That's really less than 1.5 year's cash flow using modest assumptions. And I guess kind of related to one of the last questions, given how modest that future development capital spending is, is there potential to even give a modest dividend to shareholders going forward?

Dana Coffield

The board has considered that and continues to consider that. We're, at this position at this point in time, not planning on doing that simply because there's significant uncertainty on our near-term, I guess call it near-term, capital spending that could develop in Brazil and Peru. I mean, I know for the last 2 years, there's been a huge demand for dividend stocks. Quite a few of our peers have done that. Our peers that have done that are underperforming Gran Tierra. Companies today are borrowing money to pay dividends, maintain dividends. So given the potential capital spend we see coming, we're, again, being conservative, as you said, to ensure that we don't trip over ourselves by making commitments that we don't want to fulfill going forward. We still think our best use of our capital is putting in the ground, finding reserves and developing those reserves, growing production, growing cash flow.

Michael Letros

I would agree with all those points. The only pushback I would give and just leave it at that is that I think when you look at the other companies and their future development costs or commitments relative to what yours are on a cash flow basis, these are extraordinarily attractive, and I think it's a real testament to what you guys have built here but also, I think, provides maybe a bit more leeway to actually sustainably pay a dividend. But anyways, just one shareholder's thought.

Operator

Our next question is from Mr. George Toriola of UBS.

George Toriola - UBS Investment Bank, Research Division

I was just going to follow-up again on Peru. Can you sort of refresh on the difference between the 2C and 3C estimates, the basis for the 2C and 3C estimates of Bretaña?

Dana Coffield

Yes. The estimates are based on the original well drilled by Amoco in the mid-70s and the basis -- the primary difference is an area that this is away from the discovery well. So the 1C would be the immediate area around the discovery well. 2C area or the 2C reserves would be the next step out drainage areas, sort of the drainage areas. And 3C would be upward of that. That's the primary difference in the numbers is the area that's used for the reserves.

George Toriola - UBS Investment Bank, Research Division

So does the well reserves you have give you any indication whether you're closer to 2C, 1C, 3C, something like that, based on area that you now can [indiscernible]?

Dana Coffield

Well, you would -- there'll be a shift in 3C to 2C to 1C. But now you [indiscernible] that shift, I can't say at this point in time. And in fact, we bring forward a commercial early development plan and we should actually see these contingent numbers moving to reserve numbers -- becomes reserve numbers versus contingent numbers.

James Rozon

Contingent resource.

George Toriola - UBS Investment Bank, Research Division

Understood. Well, sort of on the basis of just area, are you closer to a 2C or a 3C or 1C?

Dana Coffield

I can't really say right now.

Operator

I'm afraid that's all we have time for, ladies and gentlemen. I would now like to turn the conference back to Mr. Coffield for closing remarks.

Dana Coffield

Okay. Well, I'd like, once again, to thank everyone for joining us today. We look forward to speaking with you next quarter to update you on our progress. I hope everyone has a good week. Thank you.

Operator

Thank you very much, ladies and gentlemen. That concludes today's conference call. You may now disconnect your lines. Have a good day. Thank you.

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