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Gran Tierra Energy (NYSEMKT:GTE)

Q2 2011 Earnings Call

August 09, 2011 10:00 am ET

Executives

Martin Eden - Chief Financial Officer, Principal Accounting Officer and Vice President of Finance

Shane O’leary - Chief Operating Officer

Analysts

Martin Molyneaux - FirstEnergy Capital Corp.

Nathan Piper - RBC Capital Markets, LLC

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

Brad Virbitsky

Rafi Khouri - Raymond James Ltd.

J. Frederick Kozak - Canaccord Genuity

Alexander Klein - Dundee Securities Corporation

Howard Farkas

Unknown Analyst -

Ian Macqueen - CIBC World Markets Inc.

Quinn Sievewright - Stifel, Nicolaus & Co., Inc.

Operator

Good morning, ladies and gentlemen, and welcome to the Gran Tierra Energy's results conference call for the 3 months ended June 30, 2011. My name is Nicole, 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, August 9, 2011, at 10:00 a.m. Eastern Standard Time.

Please be advised that in addition to historical information, certain comments made during this conference call, particularly those anticipating future financial performance, business prospects and overall operating strategies, constitute forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Such statements may be identified by words such as anticipate, believe, estimate, expect, intend, predict and hope or similar expressions. Such statements, which include estimated or forward-looking production and financial information or results, are based on management’s current expectations and are subject to a number of factors and uncertainties, which could cause actual results to differ materially from those described in the forward-looking statements. Listeners are urged to carefully review and consider the various disclosures made by Gran Tierra Energy and 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 August 9, 2011, and in its annual report on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange Commission, February 24, 2011. If one or more of these risks or uncertainties materialize or if the underlying assumptions prove incorrect, Gran Tierra Energy’s actual results may vary materially from those expected or projected. Listeners are urged not to place undue reliance on forward-looking statements made in today’s conference call. Gran Tierra Energy assumes no obligation to update these forward-looking statements, other than as 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 last night includes a reconciliation of this non-GAAP item with the company’s GAAP net income, as well as the information about why management believes this measure is useful in evaluating the company’s performance, and is 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 the property of Gran Tierra Energy, Inc. Any copying or rebroadcasting of this call is expressly forbidden without the written consent of Gran Tierra Energy. I will now turn the conference over to Shane O'leary, Chief Operating Officer of Gran Tierra Energy. Mr. Leary, please proceed.

Shane O’leary

Good morning, and thank you for joining us for Gran Tierra Energy's Second Quarter 2011 Results Conference Call. With me today is Martin Eden, our Chief Financial Officer; Dana Coffield, our President and Chief Executive Officer, is unable to join us today as she is meeting Canada's Prime Minister Harper in Brazil this morning, following the Prime Minister's meeting with President Dilma Rousseff. Dana will be meeting the Prime Minister again tomorrow in Colombia, prior to the Prime Minister's meeting with President Santos.

Last night, we disseminated a press release that included detailed financial information about the quarter. In addition, Gran Tierra Energy's 2011 report on Form 10-Q for the 3 months ended June 30, 2011, has been filed on EDGAR and is available on our website at www.grantierra.com.

I'm going to begin today by talking about some of the key developments for the quarter. Martin will then take a few minutes to discuss key aspects of this quarter's financial results. I will provide an operational overview and closing remarks.

The second quarter of 2011 was highlighted by record production and the first full quarter of production from the Petrolifera assets acquired earlier this year. The quarter was also highlighted by initial long-term test production from the Moqueta discovery, which is now flowing through a newly constructed flow line back to our Costayaco facilities. Gran Tierra Energy obtained average quarterly production sales in the second quarter of 18,141 barrels of oil equivalent per day, net after royalty, comprised of 15,277 barrels of oil equivalent per day in Colombia; 2,820 barrels of oil equivalent per day in Argentina; and 44 barrels of oil per day in Brazil. Contributing to the second quarter increase was existing fuel developments, new production from recent field discoveries and production growth from recently acquired Petrolifera assets. This also represents an increase from our first quarter 2011 production of 13,476 barrels of oil equivalent per day, which was impacted by downtime at the Tumaco Port. Approximately 97% of our production is light and medium oil.

Funds flow from operations for the quarter doubled to $88.6 million compared to the same quarter last year. Funds flow for the first 6 months was $155.1 million, which contributed to a cash and cash equivalents balance of $211.4 million.

Operationally, Gran Tierra Energy had another busy quarter. In Colombia, we completed the construction of the new pipeline to connect our Moqueta oil discovery to our existing infrastructure at Costayaco. We experienced our first test production from that field at the end of June. In April, we completed drilling the Moqueta-5 delineation well to a total measured depth of 5,309 feet. Based on initial data, the Caballos, T Sandstone and U Sandstone reservoirs appear to be saturated with oil with a total net pay of 167 feet with no water evidenced in the logs.

Finally, we participated in the drilling of one exploration well in Melero-1 in the Garibay Block operated by CEPSA. This well had shows while drilling and oil interpreted from logs. Testing will be initiated on this well soon. Let me now turn the call over to Martin Eden to discuss the financial results before I come back with more details on operations. Martin?

Martin Eden

Thanks, Shane, and good morning, everybody. Financially, the second quarter of 2011 was very strong for Gran Tierra Energy. Revenue and interest income for the second quarter of 2011 was $162.1 million, a 93% increase from the same quarter in 2010 due to increased production and an increase of 45% in realized crude oil prices. The average price received per barrel of oil equivalent increased by 42% to $97.93 per barrel for the 3 months ended June 30, 2011, from $68.78 per barrel from the same period in 2010. Operating expenses for the second quarter of 2011 amounted to $23.2 million, compared to its $9.5 million recorded in the same quarter last year. The increase in operating expenses was mainly due to the initial assets acquired in the Petrolifera acquisition, along with additional work over, fuel and power, water injection and trucking costs. On a barrel of oil equivalent basis, operating costs increased 79% to $14.03 from $7.83 for the second quarter compared to the prior period. General and administrative expenses of $16.4 million for the 3 months ended June 30, 2011, were higher than the comparable periods last year, reflecting expanded operations and the acquisition of Petrolifera. G&A expenses per BOE increased 26% to $9.94 for the current quarter compared to $7.88 per BOE for the second quarter of 2010, due to the same factors.

Depleciation -- sorry, depletion, depreciation, accretion and impairment expense, DD&A, for the current quarter increased to $47 million, compared to $31.6 million for the same quarter in 2010. The increase was attributable to higher production levels as the depletion rate at $28.45 per BOE remained comparable to the same quarter last year. Increased levels of costs in our depletable pools were offset by higher reserves. DD&A expense for the second quarter of 2011 also included the full quarter of DD&A of $4.2 million related to properties acquired from Petrolifera. Included in the second quarter 2011 results is the foreign exchange loss of $14.5 million, of which $11.6 million is an unrealized non-cash foreign exchange loss. This compares to the $3.1 million foreign exchange loss recorded in the same quarter of 2010, of which $1.3 million was an unrealized non-cash foreign exchange loss. The unrealized foreign exchange losses arise primarily as a result of the translation of a deferred tax liability. The deferred tax liability is denominated in Colombian pesos and the decline in the U.S. dollar against the Colombian peso of 5% from the current quarter, compared to 1% for the 3 months ended June 30, 2010, resulted in the foreign exchange losses. The net impact of these factors resulted in net income of $31.6 million in the second quarter of 2011, compared to net income of $17.4 million in the same quarter of 2010. This equates to earnings per share of basic and diluted of $0.11 for the second quarter of 2011, compared to $0.07 per share that basic and diluted, for the same period last year.

Funds flow from operations in the second quarter was $88.6 million compared to $44.3 million in 2010, reflecting the significant increase in crude oil production and the increase in oil prices. Funds flow from operations is a non-GAAP measure based on GAAP net income or loss, adjusted for depletion, depreciation, accretion and impairment, deferred taxes, stock-based compensation, unrealized gain on financial instruments, unrealized foreign exchange gains or losses, settlement of asset retirement obligations, equity taxes and gain or loss on acquisition. Our reconciliation to net income is included in our second quarter 2011 earnings press release.

Our cash and cash equivalents were $211.4 million at June 30, 2011, compared to $355.4 million at December 31, 2010. The bank debt of $31.3 million reflected in the balance sheet as of June 30, 2011, represents the reserve-back credit facility acquired as part of the Petrolifera acquisition. Gran Tierra Energy repaid all amounts owed under the Petrolifera's reserve-back facility on August 5, 2011, and Gran Tierra Energy is now again debt-free.

Working capital, including cash and cash equivalents, decreased to $215.4 million at June 30, 2011, as compared to $265.8 million at December 31, 2010, due mainly to lower cash and cash equivalents and the bank debt acquired from Petrolifera, offset partially by a $113.3 million increase in accounts receivable, mainly due to timing of payments from Echo Petrol.

That concludes my comments. I would now like to turn the call back to Shane for an update on Gran Tierra Energy's 2011 capital plan and outlook.

Shane O’leary

Thank you, Martin. Our Colombian program includes drilling 7 exploration wells this year and total planned capital expenditures of $196 million. On the Chaza Block, Gran Tierra Energy completed the 6-inch diameter, 8-kilometer flow line connecting the Moqueta oil discovery to existing Costayaco infrastructure. Production from the Moqueta field is expected to be modest and intermittent as wells are tested at rates of approximately 500 to 700 barrels of oil per day. New 3D seismic acquisition is expected to start in the third quarter to assist in refining the mapping of the Moqueta field and planning further delineation and development drilling. Development planning is underway and production from Moqueta is expected to ramp up in the first half of 2012 as fuel development gets underway.

Initial Production tests at Moqueta-5 were conducted on the T Sandstone reservoir and will eventually be performed on all zones. Testing over 10 days resulted in production rates of 730 relative oil per day with a jet pump. Testing on this well and other wells drilled in the field will continue through the balance of the year. Moqueta-6 expected to spud in the third quarter of 2011 will be drilled as a deviated well from the Moqueta-4 service location to further investigate the down dip limits of the oil columns encountered in the Villeta U, Villeta T and Caballos formation reservoirs. Permitting for a new location for Moqueta-7 is ongoing.

Costayaco-14 development well is currently being drilled and is planned to be used as a water injector for pressure support for the Costayaco Field. The Costayaco Field was connected to the national electrical system during the quarter, which is expected to marginally improve operating costs in the area going forward.

On the Sierra Nevada Block, development of the Brillante gas field is advancing, with the first gas yield expected to be initiated in the third quarter with compressed natural gas trucking at approximately 2 million to 3 million cubic feet per day. A new 275 square kilometer 3D seismic program is expected to be acquired in the third quarter of 2011, of which 222 square kilometers will be in the Sierra Nevada license and 53 kilometers will be in the Magdalena license. The Brillante SE-2x delineation well is expected to evaluate the significant potential gas resource discovered by Brillante SE-1x and is expected to spud late in the third quarter of 2011. In the Guayuyaco Block, the Juanambu-3 development well drilling operations were completed in April of 2011 and production tests are ongoing. On the Garibay Block, the Melero-1 exploration well reached total depths of 9,748 feet on July 16, 2011. Oil shows are present in the Mirador formation. The testing program is currently being prepared. Additional exploration wells expected to be drilled during the remainder of 2011 include the Rumiyaco-1, oil exploration well expected to be drilled in the third quarter of 2011 and the Turpial-1, La Vega Este-1 and the Pacayaco sidetrack oil exploration wells, which are expected to be drilled in the fourth quarter of 2011.

In Peru, a drilling location has been identified for the first exploration well on Block 95, with civil construction expected to begin in the third quarter of 2011. This well will evaluate an oil field discovered by Amoco in 1974 that tested 807 barrels of oil per day and will also explore deeper reservoir horizons not penetrated by that discovery well. Permitting for drilling on Block 107 is advancing, with drilling expected to begin in the second half of 2012. Geologic studies and permitting activities are ongoing on the adjacent Block 133 in preparation for seismic acquisition in 2012. Government approval for Gran Tierra Energy's 20% non-operated working interest in ConocoPhillips operated Blocks 123, 124 and 129 was granted on March 19, 2011, with final assignment completed April 26, 2011. Gran Tierra Energy is evaluating the prospectivity of Blocks 123 and 129, based on recently acquired 2D seismic data together with its partners on the Block. Additional infield 2D seismic data will be acquired on these blocks in late 2011.

In Argentina, Gran Tierra Energy has initiated its work over program on 16 wells in the Puesto Morales field, of which 10 have been completed. Geological and geophysical studies are ongoing to optimize the location of the planned 6 development wells in the fourth quarter. The goal of these wells is to improve recovery in the remaining reserves and grow production. In addition, detailed geological and reservoir models are being created to assist in redesigning the existing poorly performing waterflood. Since taking over operatorship in March, production decline of the last several years has been halted with the work over program and production has increased to approximately 2,530 barrels of oil equivalent per day. In Brazil, Gran Tierra Energy received final approvals for a 70% working interest and operatorship of Blocks 129, 142 and 224 and 155 in the onshore Recôncavo Basin in April 2011. Gran Tierra Energy anticipates drilling 2 development wells in the second half of 2011 to grow production from this discovery, which is currently producing about 500 barrels of oil per day gross, or approximately 350 barrels of oil per day net, after royalty, from one zone without the assistance of pumps. In addition, 2 horizontal exploration wells are planned to be drilled on this acreage in 2011, with drilling rigs currently being tendered and locations currently being permitted. Additional drilling is scheduled to continue into 2012. The first exploration well is expected to start drilling on Block 142 at the end of the third quarter 2011.

In summary, Gran Tierra Energy has a catalyst-rich remainder to the year, while remaining financially strong with the 2011 capital spending program of $357 million for exploration and development activities. We are financing our capital program through internal cash flows and cash on hand, while retaining financial flexibility with a strong cash position. Gran Tierra continues to anticipate 2011 production since the acquisition of Petrolifera at average between 17,500 and 19,000 barrels of oil equivalent per day. Gran Tierra is again debt-free.

The record production we achieved this quarter will support our robust exploration and drilling programs for the remainder of the year and into 2012. We look forward to communicating our progress as we proceed through the back half of 2011. That concludes our prepared remarks for this morning. We would now be pleased to answer any questions you might have.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question will come from the line of Martin Molyneaux of FirstEnergy Capital Corp.

Martin Molyneaux - FirstEnergy Capital Corp.

With regards to Moqueta, you've got the 2 more wells in the drilling schedule and you're going through the testing sequence with the existing locations, how do you see the development plan unfolding here and at what point in 2012 do you think you get to hold your development?

Shane O’leary

Well, we're still trying to determine the tank size and that's critical in order to size facilities. Moqueta development will probably have both gas injection and water injection and we still don't have seismic over the 3D seismic, over the northern part of the field. It's in consultation for the permitting process and it's a mandatory 6-month period so that has slowed things down a little bit. But I would say by the end of the year, we'll have an adequate understanding of the reservoirs. We can come up with a depletion plan, an understanding of the tank size. We can size facilities and then we can start proceeding quite quickly. So I see ramp up in 2012. It's a little difficult to pinpoint the exact quarter at this point. It is a heavily-supported area, too, which makes the logistics a little more complicated. But the good news is that it keeps getting bigger. We've done some field work recently and it's moved the fault to the north. The news that we're getting from Moqueta continues to be very positive and that's what we need to understand, it's just how big this thing is.

Operator

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

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

Just a couple of quick questions. To start off, could we just run through kind of the water injection response you're seeing at Costayaco currently, from a pressure perspective? And then also your outlook for production at Costayaco over the next 12 months and that when you expect to start seeing declines there?

Shane O’leary

Well, we're currently injecting about 6,000 barrels a day into the T Sand only. Both horizons have aquifer support but the aquifer support is much stronger in the Caballos reservoir than the T Sand. We've seen nothing short of a stellar pressure response to the water injection so far in the T Sand, or had immediate pressure buildup and that's allowed us to actually open up the T Sand formation at some of the wells and maintain production where we're at. In the northern part of the reservoir, we want to inject water into the Caballos as well and that's what Costayaco-14 will allow us to do. We've had some drilling issues with 4 teams. It's taking a little bit longer than we'd like. But all indications are -- is that the waterflood is performing extremely well at Costayaco. We're currently producing less than we could at Costayaco and we're deliberately doing that for prudent reservoir management. And we'd like to extend the plateau as long as we can and so far it's hard to predict exactly when we'll come off plateau but so far, the reservoir has been performing very well.

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

And then just a quick follow-up on those, could you give us an update on Juanambu-3 on the development well there and kind of where things stand? And then also if there's any further details on the Melero-1 log and kind of what's our net pay you saw there or kind of how you guys are viewing that well?

Shane O’leary

Juanambu-3 will be a producer. Reservoir quality wasn't quite as good as Juanambu-1 and 2 and we're still actually testing one of the zones but it'll be a producer, and will contribute to our production. Melero, I don't know if there's much more I can say. We're waiting for the test results and the operator hasn't released any more information than we have. I don't think so. But indications are that it's a discovery. How big, I think, it'll be on the small side. It's in Llanos, typically Llanos kind of stuff. But indications are that it's a discovery and we'll find out more with the test program.

Operator

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

Nathan Piper - RBC Capital Markets, LLC

A couple more follow-ups on the operations. First of all, on Moqueta, tell us the buildup on what Martin was chatting about and you've got a 20,000-barrel a day pipeline, I think, that you've now hooked up. You're saying that testing per well would be around about 500 to 700 barrels a day, but what I'm trying to understand is where do you think the long-term or where do you think the ramp up production rate will be per well? I think what you've told us previously, it was a bit like Costayaco, so if we would be thinking of 1,000 to 4,000 barrels a day per well, or is that a bit too optimistic?

Shane O’leary

The 750 barrels a day was only from the T Sand reservoir. We're testing them separately. We're trying to collect as much reservoir information as we can and so there's a flow period for a week or 2 and then a buildup period, and so on. So it's not a continuous flow yet either, and we'll be testing several of the wells in Moqueta. So if we're getting 750 from the T Sand, we'll probably get something like that from the Caballos. Maybe a little bit less. So yes, we're kind of looking at something in the order of 1,000-plus barrels per day from -- I don't expect we're going to get 20,000 barrels a day out of Moqueta. Of course, we don't know how big it is. We've sized the pipeline obviously for the maximum possible case but it'll be a sizable field. I mean, the average field size in Colombia is sort of 4 million to 5 million barrels and this will exceed that considerably.

Nathan Piper - RBC Capital Markets, LLC

Okay. But I mean, if some of us have got something like 15 million or 20 million barrels in our models, are we being a bit too presumptuous or just between us guys, do you think that's about right?

Shane O’leary

Well, you saw the GLJ year-end numbers and I'm trying to remember what their 3P was. I think they have something like 10 million barrels for 3P and I would say that you're going to see reserve growth in Moqueta as we continue to drill wells. I mean the GLJ report at the end of December did not have Moqueta-4 and 5 in it, for example. Those were both very good wells, so you'll see reserve growth at Moqueta.

Nathan Piper - RBC Capital Markets, LLC

Very good. I'm just looking at further down the track, to the Rumiyaco well. What's the sort of potential we should think about there and appreciate that Melero-1 is not terribly exciting but my guess is that Rumiyaco is a -- has a potential to be sizable, what kind of range would you put in for that?

Shane O’leary

Jason, can you tell me what you communicated to the marketplace about that? Jason, no, I guess, he's not -- but I mean, Rumiyaco is a really nice-looking structure in a great location. There's oil fields all around it so we have high expectations for it. I'd say it could be in sort of the 10 million-barrel-plus kind of range. I don't know exactly what we said but that would be what I would indicate.

Nathan Piper - RBC Capital Markets, LLC

Okay. And one final question, perhaps for Martin. On the tax side, Martin, I guess a little bit surprised to see that your -- the taxes, it's so high still. And I guess Q1 is taking into consideration a bit of probably equity to tax, do you expect the tax has led to stay as high? I mean, compared to some of your peers, percentage-wise, it's a bit higher.

Martin Eden

Yes, it's usually high. But we actually only pay tax in Colombia. That's the only place we pay taxes. So in all the other jurisdictions, we have tax losses or -- and so we take valuation allowances against those losses and that what bumps up our rate. So the answer to your question is yes, I would expect it to stay high.

Operator

Your next question comes from the line of Alex Klein of Dundee Securities Limited.

Alexander Klein - Dundee Securities Corporation

I just have a few questions here. First of all, on the receivables side, you did mention, Martin, that the receivables increased due to timing of receivables from Ecopetrol. I just want you to confirm that we're likely to see that receivables balance decrease going forward as Ecopetrol makes its payment. Is that a fair statement?

Martin Eden

What happens with Ecopetrol is at the year end, at December, they accelerate payment of their receivables. So December 31, get 19 days sales and receivables from Ecopetrol. And the rest of the year, it's kind of normalized the 2 months or 60 days. So it stays high the rest of the year then if Ecopetrol did the same thing at year end, it'll decrease to 19, 20 days again during the year end.

Alexander Klein - Dundee Securities Corporation

All right. And then just with regard to Brillante, you mentioned that you're starting gas sales through trucking. I'm just wondering what kind of pricing you're expecting on your gas sales out of that area?

Shane O’leary

The trucking CNG scenario is something that we inherited from Petrolifera. They entered into this arrangement to demonstrate the commerciality of the Brillante-1 discovery. So that is by no means, we're looking at in terms of the full field development. Brillante-2 is successful, which we hope it is. I think we're getting something in the order of like $2 to $2.50 for the CNG. But our market analysis for the later field development is indicating prices anywhere from dollars per MMBtu and that's more what we're looking to long-term for this potential development.

Alexander Klein - Dundee Securities Corporation

Sorry, I didn't catch that price. For some reason, the line went out when you mentioned it.

Martin Eden

Which one, the CNG?

Alexander Klein - Dundee Securities Corporation

No, the pricing, your long-term pricing.

Shane O’leary

Long-term, we're sort of looking at $4.50 to $6 per MMBtu.

Alexander Klein - Dundee Securities Corporation

Okay. And just final question. Generally speaking, obviously, with volatility in the oil markets right now, just wondering what kind of WTI benchmark pricing you guys used when you put your capital plans together? Going forward?

Martin Eden

But scientifically, usually, it's $85 WTI for the balance of the year. And obviously, there's a lot of turbulence right now but that's what we've kind of used. Although we're sensitive it is -- on that, as well.

Operator

Your next question comes from the line of Ian Macqueen of CIBC World Markets.

Ian Macqueen - CIBC World Markets Inc.

Couple of questions. One thing I've noticed for sure is that your operating costs have bounced around. I think that mostly has do with number of work overs at Costayaco. But there seems to be increasing trend on operating costs just in general in Colombia? Can you comment on expectations of a on a per-barrel basis on where you expect operating cost to be in the future?

Martin Eden

Well, if you look at our operating costs in Colombia, they're about $11 a BOE, and I think we would anticipate something similar for the balance of the year. I think what's happened in the quarter, total OpEx is about $14 of BOE and it's really impacted by Petrolifera. We have $4.5 million of Petrolifera in there so on a consolidated basis, we're still looking right about $14 of BOE for 2011. And you're right, it does jump around depending on the number of work hours we're doing so.

Ian Macqueen - CIBC World Markets Inc.

Okay. The other thing I noticed is that G&A seems to be going up, probably with Petrolifera. So it's about $16 million for the quarter. Is that a pretty reasonable estimate for quarterly basis going forward?

Martin Eden

A couple of items in the G&A, we have $1.2 million of Petrolifera acquisition costs. And we also have about $800,000 interest expense on the Petrolifera debt. But having said all that, we're obviously -- we are hiring a lot more people as part of our business development activities in Brazil and also in Calgary. So in terms of where we think we're going to be for the year, we're looking at about $9.30 a BOE, which is about, sort of, about $60 million, just a little bit over, and just kind of double where we are for the first half. So we're on trend to what we think it's going to be.

Shane O’leary

I would just add, we're aware of the G&A and one of the things we're trying to do to help reduce G&A is do more work from Calgary. Historically, I think Gran Tierra has had pretty much autonomous business units in country and ran most of the operation from within country. But we're finding that it's actually a lot cheaper to hire people in Calgary and the quality of the people is extremely high and so on, and run some of the work out of some of the newer countries that we're in from Calgary. So I think you'll see more of that to help control some of the G&A.

Ian Macqueen - CIBC World Markets Inc.

Sounds good. And then I have a number of questions on the operational side as well. So starting with, I see that you've laid the gas line from Costayaco to Moqueta. There is gas production I've known but what kind of volumes are you expecting to be able to inject, coming from Costayaco into Moqueta, and what's done with the gas right now?

Shane O’leary

There's about 4 million a day, I think, that's available now. It fluctuates but it's currently, a lot of it is layered at Costayaco. We had some plans trying to generate electricity with it and it wasn't very economic. So that's the gas that would be available through the exploration program. We have a large gas cap at Moqueta so obviously, we'll be injecting into that but that's not -- we don't need the pipeline for that. But the gas line, in addition to the oil line, just gives us a lot of flexibility down the road to move product around for pressure maintenance and that was the idea behind it.

Ian Macqueen - CIBC World Markets Inc.

Okay. To follow up on Alex's question, on Brillante gas. So to begin with the CNG, I'm expecting, is that $2.50, is that more like a net back, or is that a price which you still have to pay transportation costs on?

Shane O’leary

I don't remember. I don't know, we'll have to get back to you on that one.

Ian Macqueen - CIBC World Markets Inc.

It's more like, the first stage is really to prove that it's going to work to test the wells, that kind of thing. And then getting into a longer-term program, you'd hopefully get better pricing related to the regulated market price and then minus a transportation cost.

Shane O’leary

Yes, I mean, I'm not sure we'd do the CNG thing if we started it today. It was something that was done purely to demonstrate that the resource that had been discovered was economic, which is one of the things you have to do to book reserves. But it's not the long-term solution for gas in this area. We're only, I think, we're 70 kilometers away from the grid system, though with the Brillante-2 well, we're hoping to prove up a minimum tank size for an economic gas development at those prices that I indicated earlier.

Ian Macqueen - CIBC World Markets Inc.

Okay. Moving on to Brazil. Your production now, I guess, is about 250 barrels a day. You have 2 development wells. Can you give us an idea of what you expect your exit rate to be for Brazil?

Shane O’leary

Yes, if we can get the -- that the wells drilled by the end of the year, which is the plan, we've had some issues with securing rigs, but I think we're very, very close to signing rigs up. The 500 barrels a day we're getting is only from one of the productive horizons. For some reason, Alvorada did not open up the second horizon. There's 2 formations, one's called the Sergi and the other one's the Agua Grande. And they're both very prolific producing formations within the Recôncavo Basin. And on logs, we see pay in the other formations. It just hasn't been perforated. So we should be able to get about 1,000 barrels a day out of these wells, very conservatively. By the way, the 500 barrels a day we have to choke back just to make sure that we're not going to comb the water or anything like that. So I would say we can get 1,000 barrels a day. We drilled 2 more wells. That's another 2,000 barrels a day of incremental production and at some point, we will recomplete the well that's on production now to open up that second zone.

Ian Macqueen - CIBC World Markets Inc.

If I remember correctly, there was, I think, an estimate of about 5 million barrels as a recoverable target size. Does that include both zones?

Shane O’leary

Yes, that's an unaudited number. I think we've thrown out in the past, 6 million, something like that.

Ian Macqueen - CIBC World Markets Inc.

Great. And then on the exploration front, obviously, it's welcome news to see that you're doing some exploration in Brazil. Can you just go over again the target size, kind of rates and chance of success for the 2 exploration wells in Brazil?

Shane O’leary

It's a shale with a turbidite sand in it. It's never been tested with a horizontal well. I'd say it's not a Bakken-type thing. There's actually sand and mixed in with the shale so it's got more permeability and porosity, hopefully. So the idea is to drill horizontal wells into this or into this shale sand and see what it does. We know that it's charged with oil because there's been literally hundreds of vertical wells that have been penetrated this thing in the area. So we know it's got oil. It's just a question of will it flow at economic rates. Our hope is to get something like 300, 400 barrels, possibly, out of each of these wells. We have 20 locations mapped on 3D seismic on our blocks alone. So that's the reason we actually went into these blocks, it was for that upside. If it works, you do the math, 20 wells, 300, 400 barrels of oil, that's pretty material production for a company like Gran Tierra.

Ian Macqueen - CIBC World Markets Inc.

And have you given an idea what the target size would be?

Shane O’leary

No, not really. I mean, if you're getting 300, 400 barrels a day, maybe 10 million, 20 million barrels would be something that we would hope for.

Ian Macqueen - CIBC World Markets Inc.

Okay. Great. One last question. On Peru, Block 95, there's obviously a historic discovery, if you were to actually find oil in your follow-up well, what's the infrastructure situation? And when could we expect first production?

Shane O’leary

Well, we're probably looking at a barge-type scenario, initially, anyway, and I would say it's, because of the remote location, it's probably a couple-of-years-type development. We have to do some appraisal drilling of the discovery and probably barge it to pump station 1, I think it is. So I would say a couple of years anyway.

Operator

Your next question comes from the line of Rafi Khouri from Raymond James.

Rafi Khouri - Raymond James Ltd.

A few follow-up questions on what the other guys were asking. Shane, maybe circling back on the potential oil you can find through all the wells you're going to be drilling. Back in January, I think one of the presentations had 15 million barrels risked for the Colombia program for the year, and then 16 million risked for Brazil. We've seen a few wells go down in Colombia. Is there sort of an updated number that you could share with us for what's left for the balance of the year?

Shane O’leary

I don't think we've changed those numbers, Rafi. I think we're still -- that was on a risk basis and the portfolio still has most of those wells in it so I would think it hasn't changed.

Rafi Khouri - Raymond James Ltd.

So Pacayaco, to sort of sidetrack, wouldn't be very different than what you might have had it earlier in the year? Although you've done 6 more months of work on the area maybe?

Shane O’leary

Well, Pacayaco is an interesting one. We drilled it on 2D seismic and I think we learned our lesson on that, don't drill the foothills on 2D seismic. We actually drilled along a fault plane and we couldn't have drilled the well in a worse spot. So we're going to re-enter that well and sidetrack to where we can see formation on 3D seismic. But we're still very hopeful for Pacayaco and it looks more complicated than it did originally but I wouldn't say we changed our resource estimate on a risk basis, based on anything we learned from the 3D seismic.

Rafi Khouri - Raymond James Ltd.

And then one more, in sort of looking out to 2012 and we still have a few months ahead of us but, Martin, one of the questions that people have been throwing is assuming oil keeps sliding here, sort of what's a, given the cash balance that you have, what would be maybe the sort of lowest budget oil number that you'd be comfortable with, if you had to come up with it tomorrow?

Martin Eden

In terms of what we could survive at? What pricing?

Rafi Khouri - Raymond James Ltd.

What would you drain your budget at? Not necessarily sort of survival mode, but what would you, if you're budgeting 2012 tomorrow, given your cash balance and sort of what oil's doing right now, what number would you be using?

Martin Eden

Well, we haven't decided that but we'd likely, probably drop it to, I think we used $75 this year, at the beginning of this year. Then we bumped it up a little bit to $85 in Q1. If we're going to do 2012, I'm done with the crystal ball at this time, but we make that decision. But we'd likely what we usually do, we'd pick a price, maybe the $75 and then we do a range of sensitivities, see what we can live with. So obviously, we'd look at our cash resources and we'd sort of adjust our program correspondingly. Or we look at other -- potentially look at other sources of financing. But we haven't quite got there yet. Obviously, the price of oil is a little bit unpredictable right now. But I think if you asked me today I'd pick $75.

Operator

Your next question comes from the line of Frederick Kozak of Canaccord Genuity.

J. Frederick Kozak - Canaccord Genuity

Just a couple of questions, most of mine have been answered already. Can you provide any further commentary on the dispute that you're having with the ANH on the Chaza contract?

Shane O’leary

From the technical -- I'll let Martin address it as well, but from a technical point of view, those are -- our interpretation of the contract is that the $5 million barrel threshold is on a field basis, and there's an absolutely nothing technically similar between the Moqueta field and the Costayaco field. They don't have the same oil and water contact. They don't have the same pressure regime. 9,000 feet. One at 4,000 feet. These are separate fields and so we're very confident that ultimately, our position will prevail. That's sort of my technical look at the situation. I'll let Martin comment on it from a commercial point of view.

Martin Eden

We haven't heard really anymore from ANH since we first disclosed this issue. So nothing's really changed in the position that we had a few months ago.

J. Frederick Kozak - Canaccord Genuity

Now one of your peers, Petrominerales is proceeding down the same path towards arbitration, is there a thinking that you might await the outcome of that or what is your thinking on that?

Martin Eden

I think Shane said that we regard our cases being a little bit different and we don't know yet whether it will proceed to arbitration. But we don't know whether the ANH is thinking, what will be impacted by the results of any arbitration outcome with Petrominerales. So we don't know yet. There's a likelihood it will go to arbitration. But we don't know at this time.

J. Frederick Kozak - Canaccord Genuity

Then my last question, just related to production coming out of Argentina. Can you just talk a little bit about first of all, your original assets in Argentina in terms of their production volumes, previous quarter, what your outlook is going forward and then a little bit more, please, about the Petrolifera assets?

Shane O’leary

Okay. Our assets in the northern part of Argentina, Noroeste Basin were 700, 800 barrels a day, really not all that material from a production point of view to Gran Tierra. We do have the Valle Morado gas asset that we're talking to other parties about now to possibly look at another well there, potential gas plus on development opportunity. The southern assets, the Puesto Morales field that we picked up from Petrolifera, I think has a lot of potential for growth. There's about 31 million barrels in place in that field and about 5 million barrels has been recovered to date and for a light oil like that, in this type of reservoir, that would be a recovery factor like 16 or 17%. You should be able to get upwards of over 30% recovery from a reservoir like this. I think there's another 5 million barrels to exploit here and that's where we think there's some real growth in that asset, both from the point of view of drilling some infield wells. But more importantly, we've got to get the waterflood working more efficiently and that's why we're doing a very comprehensive geological and reservoir model, which hasn't been done in the past. To really understand where the water's going, what we're doing is tracer surveys and so on, and redesign it somewhat so that we can get better performance. And I think there's a lot of upside if we're able to do that. So we'd arrested the decline. I think we've actually grown production since we took it over by about 550 barrels of oil per day, just by doing low hanging fruit-type work overs. We've done 10 out of 16 so far. But we stopped the decline and we've grown production a little bit. But the real upside is understanding the reservoir and having a more successful waterflood. And in that case, I think there's another 5 million-barrel-potential type thing.

J. Frederick Kozak - Canaccord Genuity

Okay. So it's then probably safe to say that your Noroeste Basin assets maintained flat production and looking for the new assets, too, potentially low for the...

Shane O’leary

We're going to drill another well at Proa. It's a development well really, so you'll probably see a bump in production up there, from that well. But it's lucky to come on in the beginning of end of fourth quarter type thing. But, yes, pretty much like you've seen the last couple of years, pretty flat production, a lot of work overs, maintenance-type work, to maintain that production.

Operator

Your next question comes from the line of Danny Hick [ph] of TD Securities.

Unknown Analyst -

All my questions have already been asked and answered.

Operator

Your next question comes from the line of Brad Virbitsky of Equinox Partners.

Brad Virbitsky

Couple of questions. First, do any of your exploration and production plans change based on $75 oil? And how low can the price of oil go before you have to change your plans?

Shane O’leary

I think the answer to that would be, no. We're dealing with incredibly high margin stuff in Colombia and I mean, oil prices would have to drop, and when they dropped -- at the height of the recession, I think, they dropped down to $35, $40 a barrel. We were still making money in Colombia. So fortunately for us, we've got lots of room before we have issues in that regard. In terms of the exploration, stuff we're looking at in Peru is pretty big stuff, particularly 107, 133. We've had some big companies approach us about farming in there. So we're looking at that. But you're talking about company-changing type size discoveries. So I don't think we're going to be impacted in the short-term by oil prices in that area either. We're debt-free. We could always, if we needed to, we could raise capital, which we don't need to do right now. So I don't think, in the sort of the range of rev, right now, is going to have any impact.

Martin Eden

Again, I mean, it's difficult to predict what the price of oil is going to be but I think as Shane said, we are flexible. We do have capacity. We can adjust our CapEx program if necessary and we may or may not look at outside additional financing. But I think we have capacity to do but I think in general, we tend to be fairly prudent in the way we conduct our operations. So and again, we're flexible. We can adjust and again, as we said before, we do have a lot of room right now.

Brad Virbitsky

One more question. I'm wondering how does the economics of your operations change compared to well, when you use helicopters versus trucks?

Shane O’leary

Well, the drilling costs are higher because you've got to move everything via helicopter. I should add that Moqueta, the Moqueta development is unlikely to remain a helicopter-supported operation forever. I mean once we make a -- once we sanction a development plan, we'll probably build a road in there just to make it more accessible. So we'll be able to deal with some of those costs. But even then, some of the locations will probably still need helicopters to access and that sort of thing but the main development will be road accessible at some point, I would expect.

Operator

Your next question comes from the line of Quinn Sievewright from Stifel, Nicolaus.

Quinn Sievewright - Stifel, Nicolaus & Co., Inc.

A number of my questions have been answered but just going back to Peru briefly, can you give any indication of the potential resource scale you see on Block 95 from the drilling this year? And what would you view as the key risks given the success of the previous well drilled on that field?

Shane O’leary

Well, because of the discovery well, the chance of geological success is like one, sort of thing. the risk is the API gravity. There was some uncertainty over what the API gravity of the Amoco discovered oil was. It ranged between 13 and 18, which could make quite a difference in terms of the economics of that development and accessing the pipeline spec and so on. The higher crude, the 18, was determined from their lab in Tulsa, Oklahoma, so we have a higher confidence level on that. And the lower one was based on field-tested API gravity and it's a long time ago. So it's hard to really assess what it is but that's probably the biggest risk. I don't see a lot of -- we're drilling the same structure so the geological risk is very, very low.

Quinn Sievewright - Stifel, Nicolaus & Co., Inc.

And can you comment on what your risk or unrisks kind of potential resource scale on that discovery might be?

Shane O’leary

It's a pretty big structure. It could be sort of 30- to 60-type thing. It's hard to say until you start delineating and testing and so on.

Operator

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

Martin Molyneaux - FirstEnergy Capital Corp.

Gentlemen, could you give us a kind of a bit of a, if you can call it a mid-term view on how you see Brazil evolving? I guess, we just learned this morning that Argentina sounds like they're going to be putting off their bid rounds. Do you still see a bid round happening in Brazil in the balance of this year? And can you kind of give us your thoughts on the evolution of Brazil in 2012 and 2013?

Shane O’leary

Well, we've been a little bit frustrated with the bid round situation. Unfortunately, it's tied up in the free salt fiscal regime matters that are going through the various levels of government in Brazil. And even though, for example, many of the areas are not pre-salt prone, so there's no reason for them to be linked but they are. We're glad we are an entrant into Brazil because we still believe that over time, it's going to open up and it's going to open up in a major way. Just because it doesn't make sense for Petrobras to be focusing so much time and energy on marginal fields and eventually we think that economics will overcome the politics of it. And so that was our key reason for entering Brazil. The potential there is just enormous. The bid rounds, we have -- our intention was to grow through bid rounds more than anything else. We think we've got some very interesting things on the blocks we have, that will keep us busy for a couple of years, and hopefully, the bid round process will begin either later this year, which is what they're calling for officially or early next year. In the meantime, I wouldn't say the deal flow is robust by any stretch of the imagination. But we are seeing some interesting things that we're looking at, some farm-ins. And we may act on some of the things that we've been working on. So it's not like Colombia where there's lots of deal flow. But by the same token, the resource size is just massive so if you're a South American player, like we are, we just think it's a really good place to be in the long-term.

Operator

Your next question comes from the line of Howard Farkas of Farkas Group Inc.

Howard Farkas

Gentlemen, could you please go again to the development plans for the acquisitions in northern Peru, the Block that you had the dry hole on and its adjacent blocks.

Shane O’leary

Yes, Block 122 and 128, of the acreage we have, they're the furthest away from the Maranon Basin per se and so the migration path was quite long. The potential there was huge. We had to drill that well. It was the key to those arch and archplays tend to be some of the largest discoveries that exist on the planet. So somebody had to drill that well. What we determined is that there was no trap and therefore, we've downgraded that Block vis-à-vis the other Blocks that we have in Peru. We're still very excited about the Blocks we have, where ConocoPhillips is the operator because they're right up against the Basin, so the migration path is a lot shorter and there's some very attractive things we're seeing so far on the seismic. And Blocks 107 and 133, that we acquired through the Petrolifera acquisition, could be the most exciting Blocks in Peru because they're right on trend with Camisea and we think that because they were acquired years ago, the fiscal terms were still very attractive and so on, and potential for very large structures. So if anything, our portfolio in Peru has been upgraded in a significant way compared with the days when all that we had was Block 122 and 128, and then we talked about Block 95, which was an existing discovery. So the portfolio has been high-graded in a big way and 122 and 128 are not as important as they were before.

Operator

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

Shane O’leary

Well, that concludes that. I'd just like to thank everybody for participating in the call. Thank you. That's it.

Operator

Ladies and gentlemen, that concludes today's conference. Thank you for joining. You may now disconnect.

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