Gran Tierra Energy Inc.
Q1 2011 Earnings Call Transcript

Published: 11 May 2011

[Operator:]

Good morning, ladies and gentlemen, and welcome to Gran Tierra Energy's results conference call for the 3 months ended March 31, 2011. My name is Sev, and I'll be your coordinator for today. [Operator Instructions] I would like to remind everyone that this conference call is being webcast and recorded today, Tuesday, May 10, 2011, at 10

[Dana Coffield:]

Thank you. Good morning, and thank you for joining us for Gran Tierra Energy's First Quarter 2011 Results Conference Call. With me today is Martin Eden, our Chief Financial Officer; and Shane O’leary, our Chief Operating Officer. 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 ending March 31, 2011, has been filed on EDGAR and SEDAR and will be available on our website at www.grantierra.com I'm going to begin today by talking about some of the key developments for the quarter. Martin will then take a few minutes to discuss key aspects of this quarter's financial results. Shane will provide an operational overview and outlook, and I will return to provide closing remarks. The highlight of the quarter was the announcement and subsequent closing of the acquisition of all of the issues and outstanding shares and warrants of Petrolifera Petroleum, which closed on March 18, 2011. This acquisition is significant for Gran Tierra Energy as it adds undeveloped gas reserve potential in Colombia, oil exploration opportunities in Colombia and Peru and additional oil production and reserve development opportunity in a rising oil price environment in Argentina. The second significant highlight in the quarter was the continued reserve growth of the Moqueta oil field. Since the beginning of the year, we had drilled and evaluated 2 additional delineation wells, both encountering more oil than has been previously encountered. We still have not found the limits of this growing asset. No oil-water contract has been found in any of the reservoirs and any of the wells drilled today. We are now planning 2 additional delineation wells to further evaluate the extent of the oil column in the field. The next well is expected to be drilled in the third quarter. Importantly, we are also nearing completion of the flow-line between Moqueta and the Costayaco Field and are anticipating first production from this discovery in late May. In Brazil, to further complement our growth strategy, we have been qualified as a Class B operator from Brazil's National Petroleum Agency, the ANP, allowing Gran Tierra Energy to act as an operator in both the onshore and shallow water offshore in Brazil. This qualification allows us to broaden our strategy to include the offshore where we see significant opportunities in Brazil. We have had disappointing exploration results to date this year, with 4 dry holes in Colombia and one in Peru. This is unfortunately to be expected in any exploration campaign. We remain very excited about the exploration potential of the balance of our wells to be drilled in our portfolio this year and into next year to build on the exploration success that has created significant value for our shareholders to date. Gran Tierra Energy's production in the first quarter averaged 14,546 barrels of oil equivalent per day net after royalty comprised of 13,476 barrels of oil equivalent per day in Colombia, 1,070 barrels of oil equivalent per day in Argentina. This is a 1% increase compared to the fourth quarter of 2010. This production level was impacted by maintenance at the Tumaco Port crude offloading terminal on the Pacific Coast. The port was offline from December 28, 2010, to February 7, 2011. During this time, we continued production at a reduced rate to increase trucking and other pipeline transportation alternatives. Production has since grown to approximately 17,500 barrels of oil equivalent per day average for April, of which 97% is oil, with gas converted at an energy equivalency of 6

[Martin Eden:]

Thanks, Dana, and good morning, everybody. Financially, the first quarter of 2011 was a very strong quarter for Gran Tierra Energy. Revenue and interest income for the first quarter 2011 was $122.5 million, a 32% increase from 2010, largely due to an increase of 36% in realized crude oil prices. The average price received per barrel of oil grew by 36% to $94.31 per barrel for the 3 months ended March 31, 2011 from $69.20 per barrel from the same period in 2010. Operating expenses for the first quarter of 2011 amounted to $16.4 million, a 61% increase from the same period in 2010, due mainly to high workover costs, high fuel and power costs, water injection costs and higher trucking costs due to Tumaco Port maintenance in Colombia. For the 3 months ended March 31, 2011, operating expenses on a per barrel of oil equivalent basis were $12.52, an increase of 65% from $7.57 in the same period of 2010, again, due to increased operating expense coupled with a marginal decline in production from the same period last year. General and administrative expenses of $13.6 million for the 3 months ended March 31, 2011, were 90% higher than the $7.2 million for the same period in 2010, due to increased employee-related costs reflecting the expanded operations and the costs related to the acquisition of Petrolifera. Consequently, G&A expenses on a per barrel of oil equivalent basis increased 95% to $10.42 for the current quarter compared to $5.34 for the first quarter of 2010. Depletion, depreciation and accretion expense, or DD&A, for the current quarter increased to $63.4 million compared to $40.3 million for the same quarter in 2010, due primarily to a $31.9 million ceiling test impairment in our Peru cost center. On a per BOE basis, DD&A for the 3 months ended March 31, 2011, was $48.39 compared to $29.99 for the same period in 2010. Equity tax for the current quarter of $8.1 million represents a Colombian tax of 6.2% on the balance sheet equity recorded in our Colombian branches at January 1, 2011. The equity tax is assessed every 4 years. Tax for the full year period from 2011 to 2014 is payable in 8 semi-annual installments over the 4-year period, but for accounting purposes is expensed in the first quarter of 2011 at the commencement of this 4-year period. Accordingly, the equity expense for the previous 4-year period was recorded prior to 2010 and therefore, no expense is recorded in the first quarter of 2010. Included in the first quarter 2011 results is a foreign exchange loss of $5.2 million, of which $4.5 million is an unrealized non-cash foreign exchange loss. The unrealized foreign exchange loss was primarily as a result of the translation of the deferred tax liability, which is denominated in Colombian pesos. The decline in the U.S. dollar against the Colombian peso of 2% in the current quarter and 6% in the same quarter last year resulted in the foreign exchange losses. The results for the first quarter of 2011 include a non-cash gain of $24.3 million recognized on the Petrolifera acquisition. The gain is a result of the fair value of the assets and liabilities acquired as a measure for accounting purposes exceeding the fair value of the consideration given. The net impact of the above resulted in net income of $13.7 million in the first quarter of 2011 compared to net income of $10 million in 2010. Funds flow from operations in the first quarter was $66.6 million compared to $54.3 million in 2010. The 23% improvement over the same period in the prior year was primarily the result of the 36% improvement in the realized oil prices, partially offset by higher operating and G&A expenses and slightly lower production. Funds flow from operations is a non-GAAP measure measured on GAAP net income loss adjusted for depletion, depreciation and accretion, deferred taxes, stock-based compensation, unrealized gain or loss on financial instruments and unrealized foreign exchange gains and losses, the long-term push in equity taxes and the gain on acquisition. A reconciliation of the net income is included in our first quarter 2011 earnings press release. Our cash and cash equivalents were $253.9 million at March 31, 2011 compared to $355.4 million at December 31, 2010. The decline in cash is due to capital spending and partially the result of timing differences related to when Ecopetrol settles its accounts receivables. Working capital, including cash and cash equivalents, declined $41.3 million from the December 31, 2010, balance of $265.8 million largely due to the assumption of $31.3 million of debt following the closing of the Petrolifera acquisition. In summary, Gran Tierra Energy remains financially strong with the expectations of our 2011 exploration and development capital program of $357 million will be fully funded from internally generated cash flow at current oil prices of production levels and from cash on hand. That concludes my comments. I would now like to turn the call over to Shane for an update on Gran Tierra Energy's 2011 capital plan and outlook.

[Shane O’leary:]

Thank you, Martin. Gran Tierra Energy continues its work on the largest capital program in the company's history. Our 2011 Colombian program includes drilling 5 exploration wells and 2 delineation wells for the remainder of the year, along with seismic acquisition programs in preparation for additional exploration drilling in 2012. As Dana mentioned, we have not yet had exploration success this year, but we remain very excited about the pending exploration wells we have in the Putumayo, Llanos and middle Magdalena Basins. Each of our prospects in the Colombia program are independent, with the results of any one not impacting the risk of any of the subsequent prospects. We continue to have excellent success growing the reserve potential of our Moqueta oil discovery. Moqueta-4 and subsequently Moqueta-5 have both extended the depths of the known oil columns in all 5 reservoirs. No oil-water contact has been found in any of the reservoirs, indicating additional reserve potential exists further down the flanks of the structure. Up to the end of the first quarter 2012, we anticipate drilling 2 more delineation wells at the Moqueta field. Moqueta-6, expected to spud in June of 2011, will be drilled as a deviated well from the Moqueta-4 surface location in order to further investigate the down dip limits of the oil columns encountered in reservoirs. Planning is underway for Moqueta-7, expected to be drilled in the first quarter of 2012 at a new surface location approximately 1,750 meters west of Moqueta-4. This location will allow appraisal of the down dip extent of the field. Moqueta-7 could be used as an oil producer or water injector depending on the well results. First long-term test production from a new 6-inch, 8-kilometer pipeline linking Moqueta to Costayaco is expected to take place in late May 2011. Construction of the line is approximately 85% complete. Once initiated, average production from the Moqueta field is expected to be modest at approximately 500 barrels per day. Production is expected to begin ramping up in 2012 to levels that will be determined once reservoir performance data has been acquired, the full aerial extent of the field has been determined and the final development plan concept decided. Finally, new 3D seismic acquisition is expected to start in the second quarter to assist in refining the mapping of the Moqueta field and planning further delineation and development drilling. Our other significant delineation program in 2011 will be the drilling of the Brillante-2 well in the third quarter of 2011 to further define the reserve potential of this gas discovery in the lower Magdalena Basin. In parallel, we will be acquiring a new 3D seismic survey over the field to assist with the development drilling, and we have initiated the evaluation of a pipeline route to the existing regional gas infrastructure in a gas market characterized by rising demand and impending decrease in supply. In 2011, we also plan to drill 7 development wells with the intent to maintain production from our current producing assets. 4 of these wells, Costayaco-12, Costayaco-13, Moqueta-4 and Moqueta-5, were already successfully drilled in the first quarter. Moqueta-6 and Costayaco-14 are planned for the third quarter of this year. Juanambu-3 has also been drilled and is awaiting testing. In Peru, we drilled the Kanatari-1 exploration well on Block 128. Unfortunately, it did not encounter hydrocarbons, so it was plugged and abandoned. We continue to evaluate the prospectivity of the block as well the adjoining Block 122. On the adjoining Blocks 123 and 129 operated by ConocoPhillips, new 2D seismic data is being interpreted to evaluate the exploration potential of these blocks. In Block 95 to the south, plans are underway to initiate civil construction in the third quarter of 2011, with drilling expected to begin in the second quarter of 2012. An oil field has already been discovered on this block, with the discovery well drilled in 1974 flowing 807 barrels of oil per day naturally without pumps. The new exploration well will further delineate this field and will explore deeper reservoir horizons not penetrated by the discovery well. Finally, permitting for drilling on Block 107 is advancing, with drilling expected to begin in the second half of 2012. Block 107 and prospects on the block are on trend with the word-class gas-condensate discoveries that have been made in the Camisea region in southern Peru. Both oil and gas seeps are present on Block 107. Moving to Brazil. Subsequent to the quarter, Gran Tierra Energy received final approvals of assignment of interest and operatorship for Blocks 129, 142 and 224, and we expect regulatory approval for Block 155 shortly. Gran Tierra Energy will then assume its working interest share of a light oil discovery which has an unaudited estimated gross recoverable resource of 6 million barrels of oil. We are planning 2 development wells to grow production from this discovery, which is currently producing 500 barrels of oil per day gross from one zone without the assistance of pumps. In addition, we are planning 4 exploration wells, with 2 to take place this year and 2 more to follow in early 2012. 3 of these wells will include horizontal legs after drilling initial vertical pilot holes through the reservoirs, a new technology application in this area of Brazil. Drilling rigs are currently being tendered and locations are being permitted. The first exploration well is expected to spud on Block 142 in the third quarter of 2011. In Argentina, in the Valle Morado gas field, the VM.x-1001 delineation well was plugged and abandoned due to a number of operational challenges that had been encountered during sidetrack drilling operations. Gran Tierra is evaluating options to drill a new well in 2012 in what we believe is a significant natural gas opportunity in a country experiencing a shortage of gas supply. We've initiated the workover program on 16 wells in the Puesto Morales/Puesto Morales Este Blocks and are planning to drill 6 development wells and 3 water injector wells in the area. Already, our workover program has halted production declines in these newly acquired assets, and our intent is to see production growth from these fields before the end of this year. Finally, we successfully farmed out a 50% interest in the Santa Victoria block in the Noroeste Basin of Argentina to Apache Corporation. Both Gran Tierra Energy and Apache have agreed to proceed into the second exploration phase, which has a work commitment that will be fulfilled with an exploration well, which is being planned for 2012. I will now hand it over back to Dana for concluding remarks.

[Dana Coffield:]

Thank you, Shane. Gran Tierra's work program is intended to create both growth and value from our existing assets while retaining financial flexibility so we can be positioned to undertake new developments on our assets and to pursue additional acquisition opportunities where we see additional value creation opportunities. Our 2011 capital spending program of $357 million for exploration and development activities in Colombia, Peru, Argentina and Brazil includes $190 million for drilling, $79 million for infrastructure, $87 million for seismic acquisition and $1 million for other activities. Of the $190 million related to drilling, approximately $87 million is for exploration and the balance is for delineation and development drilling, a healthy split between developing existing reserves and exploring for new reserves. With this capital program and as a result of the Petrolifera acquisition, Gran Tierra has increased production guidance for 2011 since the acquisition of Petrolifera to between 17,500 and 19,000 barrels of oil equivalent per day net after royalty, with 96% of this being light oil. In Colombia, 3 additional blocks were added to Gran Tierra's portfolio following the Petrolifera acquisition

[Operator:]

[Operator Instructions] And your first question will come from the line of Nathan Piper with RBC Capital.

[Nathan Piper:]

A couple of questions if I may. Firstly, on Peru, with the Kanatari well results kind of putting you off drilling any more wells on Block 122 at the present moment, how should we take that? I mean, should we put a whole line through 128 and 122 or do you think that there will be the potential to come back to those blocks in the future? And second question, on Moqueta, if we were to take a step back here and if you were to sell to spill the current prospect side, the current structure that you see, what kind of -- what is the potential of the Moqueta structure as you understand it now? And then lastly, can you give us some guidance on your Argentina realizations? Are oil prices and gas slightly improving there?

[Dana Coffield:]

Yes, let's see. I guess, we'll go to Peru first. The current locations we have permitted, we have 4 additional locations permitted, do not have any trapping potential given the low results we have with the Kanatari well. So we're continuing to evaluate additional potentials for the future, but the reality is our portfolio has dramatically changed in Peru. Historically Blocks 122 and 128 were the priority. They no longer are. They're a part of a much larger and robust portfolio. So things like Block 95, where there's already the oil field are much higher priority for us. So it's not a top priority. It's now just part of a mix of other opportunities we have in Peru. Your second question?

[Nathan Piper:]

On Moqueta, Dana. I know I'm twisting your arm a little bit here, but how big is the Chaza Block [ph] do you think? Can you just give us some sense of scale?

[Dana Coffield:]

Well, I have to qualify we're on the same because we actually don't have a map of the entire structure. It's an anticline that's overridden by another fault, we have base in it over part of the structure and we have no seismic images below basement. So we actually don't even today know what the shape of the structure is. Hence, we're doing this in 3d seismic I'd say it's unlikely it's as big as Costayaco and -- but it's likely larger than the reserves that have been booked to date. That's kind of a rough answer, but it's the best I can do. And then Argentina realized prices, we're currently realizing $58 in the Neuquen Basin. And we are continuing to see oil prices rising as we speak in Argentina. Martin, do you want to say a few words?

[Martin Eden:]

The realized price for Argentina in the quarter was about $54.50, and typically the prices have been going up $0.50 every month. We don't know for sure if that will continue in the future. But we certainly are getting much better prices than last year. As Shane mentioned, it's higher in the south with the Petrolifera properties. The price in the south is higher than in the north, $58 versus $56.

[Operator:]

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

[Martin Molyneaux:]

Gentlemen, given that Moqueta is growing in size with the recent joint results, we've got a 6-inch line installed or about to become operational, what's the capacity of that line? And given the drilling results, are we going to have to go through a second six inch line to get to more reasonable production profile?

[Dana Coffield:]

Right now, we think we can get 20,000 barrels a day more or less through the line. So we think it's going to be adequate for a reasonable outcome. If we need to tweak it [ph] or expand capacity, it's pretty straightforward. It took, start to finish, I think it's 6 or 8 months to build this initial flow-line. I think we've got most outcomes covered with this line.

[Martin Molyneaux:]

And in terms of some kind of production ramp from the 500 barrels a day that you disclosed in the release, what's your current thinking given the well results so far?

[Dana Coffield:]

Well, it's really tough to answer because the oil is saturated with gas. So we'd either re-inject gas, maintain reservoir pressure so that gases will come out of solution from the increasing wellbores, leaving oil behind. So we really need more substantial reservoir performance data before we can provide any realistic guidance on the productivity for each well. It's a very different reservoir properties than we have in all of our oil-producing fields.

[Martin Molyneaux:]

Does that mean that you'll produce with the line operational? That means you'll produce the wells kind of in a sequence to test them out?

[Dana Coffield:]

Initially, yes. For this year, we'll actually flow individual reservoirs within each well. And then, commingle perhaps -- yes, we'll commingle reservoirs in individual wells. So this -- production this year is going to be a long-term testing program for oil-producing individual wells and individual reservoirs within those wells. And then there will be some commingling and perhaps some commingling of wells also. All that specific planning hasn't been done yet until we start getting initial data.

[Operator:]

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

[George Toriola:]

My first question sort of follows up on what Martin was talking about. 500 barrels a day, how have you -- is that just a guesstimate today or how have you arrived at that relative to your well test results?

[Dana Coffield:]

Well, some days, it will be zero and some days, it will be 1,000 barrels a day. So it's just an average a conservative average of what we think will be the production for the coming year. And we'll be doing pressure buildup tests in wells or individual reservoirs so there will be no production. And at other times, we'll be flowing wells at higher rates to see how the reservoirs perform. It's just a conservative estimate of what we expect this year averaging it out.

[George Toriola:]

Okay, thanks. And maybe to ask a bit differently as well. Would you suggest that the test rates that you've had on the wells so far, is that representative of productive capacity or you can't tell at this moment?

[Dana Coffield:]

No. No, certainly not productive capacity...

[George Toriola:]

Production potential, I should say, not productive capacity.

[Dana Coffield:]

I'll say, in our nearby existing creasing field will typically crease around 2,000 barrels a day, seeing the range from 1,000 to 4,000 barrels per day. Our concern is -- and we have the same reservoir, the same permeability and similar oil with the exception that the oil has a higher gas content. We don't want to be drawing on the reservoir at those levels until we have adequate pressure support to keep the gas in solution. So the answer is the reservoirs would expect to be able to produce somewhere between 1,000 and 4,000 barrels a day after we have compression support system in place in the field.

[George Toriola:]

Okay. So you would -- the plan is that you would re-inject all of that gas at Moqueta?

[Dana Coffield:]

Correct. That's the current thinking, yes.

[George Toriola:]

Okay, thanks. And last question here is around the ANH, the disagreement you have with the ANH, can you talk a little bit about how -- it's a little bit surprising that the Chaza Block, I'm sorry, the Moqueta structure that is not yet in production, all of this discussion is arising. Can you talk a little bit about the discussions you've had and how you expect to resolve this?

[Dana Coffield:]

Well, we actually haven't had any discussions yet. We were notified that they just recently that they were claiming payments for the test crew for Moqueta at the same rate as the payments for Costayaco. So we've sent them a letter asking them for clarification on why they think that is the case. And that's full stop all the conversation and communication that's happened to date. So it's very early days. We don't understand their position. We do understand our position. And we'll just work through it with them and sort it out.

[George Toriola:]

Okay. And your position is that -- maybe you should kind of just talk about your position. How do you interpret the 5 million barrels per structure, based on geology, how do you interpret it?

[Dana Coffield:]

Well, we don't actually interpret it. It's stated clearly in the contract with ANH that applies to each development area. You draw a polygon around your development. In which case, we have an area defined for the Costayaco field. Within that area, within that polygon, that's been defined for the development. Once production from that polygon exceeds 5 million barrels, then you pay an additional royalty. The polygon could include 2, 3 or 4 fields or just one. But in our case, in this case, it's just the Costayaco field area. The Moqueta lies outside that area.

[George Toriola:]

And there's no -- can the polygon be re-drawn? Or once it's set, it's set?

[Dana Coffield:]

Once it's set, it's set. I mean it's defined.

[Operator:]

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

[Jamie Somerville:]

Just looking at your budget for Brazil and compared to previous you have it at $60 million currently and set to get 4 wells drilled in 2011. I think you previously had $55 million in 6 wells getting drilled. Are you concerned about a slight delay in some of those wells getting drilled? I just want to check that there isn't any increase in costs going on here that maybe you can explain?

[Dana Coffield:]

No. There's been some delays. We have waited almost 6 months to get approval from the ANP for 3 of the 4 blocks, and we're waiting for the final approval on Block 155. We don't have that yet. We're coming up on 8 months. And that's impacted the drilling program. It's very difficult for us to get after it except if we work through the existing operator to get work done. So there's no question that the ANP approvals have slowed us down a little bit. There's a little bit of uncertainty as to what rig we're going to use to drill the horizontal leg for the 3 wells we've got planned, the horizontal wells. And we may be able to do it with some rigs that drills vertical pilot hole or we may not be able to. We're currently talking to various rig contractors, and we'll know soon what the situation there is. But the best estimate we have today is that we'll get the 4 wells drilled and 2 wells will spill over into 2012.

[Jamie Somerville:]

Yes, that's fine. Thanks. I think my other question is for Martin. You mentioned the accounts receivables being due to Ecopetrol-related issues. But it looks like your accounts receivables has increased by almost $100 million, which is a pretty significant amount. Did you say, is that all due to Ecopetrol and do you expect all of that to be adjusted for back to a normal level in coming quarters?

[Martin Eden:]

No. It is mostly due to Ecopetrol. I mean at year end, we have 19 days receivables, quickly run 60 days receivables. Also, the prices have increased in Q1 also. So we kind of would expect that kind of level of accounts receivable to continue.

[Jamie Somerville:]

You don't expect to go back to a lower level of 19 to 20 days?

[Martin Eden:]

Well, it will go back at year end. But it's only at year-end that, that happens. It's just that Ecopetrol at year end sort of settles it's receivables. So we typically have sort of 19 to 20 days receivables at year end. But the balance of the year, it's always 60 days. So the year-end position sort of corrects itself by the end of March, and that will continue throughout the year until December when again, we'll have 19 to 20 days receivables.

[Operator:]

Your next question will come from the line of Hubert van der Heijden with Tudor, Pickering, Holt.

[Hubert van der Heijden:]

Just looking at your price realizations in Colombia, they are above WTI. Have you been able to shift some of your contracts to Brent-link pricing? And how should we think about pricing in second quarter and onwards?

[Dana Coffield:]

We haven't linked it to Brent, but there is a clause in our contract with Ecopetrol where they are realizing higher prices. There's a formula that allows us to recoup some of that higher pricing.

[Martin Eden:]

Ecopetrol was able to sell us a premium to WTI in February or March and also in April. We don't know for sure what's going to go forward, but they're realizing better than WTI prices from their buyers and we share in that premium.

[Hubert van der Heijden:]

Okay, that's helpful. And just on the Block 95 in Peru. So the site prep begins in Q3, but the well won't spud until 2Q '12. I thought initially it was supposed to be for the fourth quarter. What is kind of leading to the delay there?

[Dana Coffield:]

It's a very difficult area and the service location. It's on the -- well, near the Amazon River, so it's flooded for a good part of the year. So it's going to take a lot of work to build a drilling platform above the flood line. So it's going to start at -- construction will start right at the end of the third quarter and then drilling will begin in the second quarter. And then there's -- we're giving consideration for using one rig for that and another block so there will be potentially some timing adjustments to accommodate drilling campaigns on 2 different blocks.

[Hubert van der Heijden:]

So there's no issue with the availability of the rig and services there?

[Dana Coffield:]

We're evaluating that right now. So there's a limited number of rigs. But right now it looks like we have 2 rigs for the drilling campaign.

[Martin Eden:]

We don't have all the permits we need. We need a deforestation permit to really start work, and we do not have that in hand. And that's one of the critical timeline issues that is still outstanding.

[Operator:]

Your next question will come from the line of Neal Dingmann with SunTrust.

[Neal Dingmann:]

Dana, with -- around the Brillante, the gas well, is the thought just to drill one well this year and then kind of after the seismic shots, see what kind of prospect there or kind of walk me through, I guess, kind of what the plans are for the next year there?

[Dana Coffield:]

There's a discovery well in the field. And then there's a lease grade of 2D seismic data. What we want to do this year is drill a delineation well to try to prove up the large 3P reserve number that we have in the field and essentially try to move as much of that into the proved category if we can, which will then allow us to undertake margin initiatives for the gas once we've proved up a reserve base. Now we're shooting the 3D seismic in parallel so that we can further define the details of the reservoir distribution that we can then use for subsequent development drilling sometime in the location of the development wells. So the objective this year is to prove up reserves with the delineation well. Next year, initiate gas marketing and pipeline construction, and then drill additional wells as required to develop the field.

[Neal Dingmann:]

So you can add some production flowing, would it be next year or would that be in 2013 then?

[Dana Coffield:]

Well, actually, we have a nominal amount of production in the beginning -- in second quarter. We sell in compressed natural gas by trucks around 2 to 3 million a day. The pipeline gas sales would probably not be until the beginning of 2013. I'd say next year is focused on developing and building pipeline sales the following year.

[Neal Dingmann:]

Okay. And is it still -- for Colombia, for exploration, including the La Vega Este-1, is there 4 -- did I get this right, you still have 4 exploration wells for the second half this year? I'm not sure if I have that right.

[Dana Coffield:]

5, I believe. There's one in the Middle Magdalena, one in the Llanos Basin and 3 in the Putumayo. The Rumiyaco, Melero, La Vega, Pacayaco-2 and Turpial.

[Neal Dingmann:]

Okay. So we have 5 distinct ones, all kind of waiting to see the outcome of those in second half of this year.

[Operator:]

[Operator Instructions] Your next question will come from the line of Nick Coutoulakis with Cannacord Genuity.

[Nick Coutoulakis:]

I guess just 2 quick questions. One, timing of Moqueta-5 flow rates. And then, secondly, regarding your assets in Argentina picked up through your acquisition of Petrolifera, just the timing of these 6 development wells. How many workovers have been performed to date by you guys? And then also what sort of production potential do you see there? I know you talked about maybe potentially a little bit of growth by the end of the year. I was hoping you could paint that picture for me, please.

[Dana Coffield:]

The test production for Moqueta-5, we expect to drill in June or July sometime, for Moqueta-5, for the test production -- I'm sorry, I think Moqueta-6. Moqueta-5 testing, we should have it in the next couple of weeks. We're doing some preliminary testing now and we'll actually begin more definitive testing once the pipeline is up and running in the next couple of weeks from now. So Moqueta-5 will have results in late May timeframe for Moqueta-5. The other question is when are we going to get the production up to what have we done so far on the Neuquen assets in Argentina. We've done approximately 5 or...

[Martin Eden:]

No. That's 16.

[Dana Coffield:]

Out of the 16 planned, we've done 5 or 6 now. If the drilling haven't started, that will be ongoing sort of back-to-back through the second half of the year. In terms of a production target, we don't have a specific number. But today, it's around 2,000 barrels of oil, 2,300 equivalent. We'd like to get up to 2,500 to 3,000 barrels a day, something like that at year end.

[Operator:]

Your next question will come from the line of David Dudlyke with Stifel, Nicolaus.

[David Dudlyke:]

A number of different questions. First of all, I was intrigued by the commentary regarding the strategy wells in Putumayo-10, Piedemonte Norte. They won't be drilled this year due to lack of appropriate slim hole rigs. These wells were marked down for the second half of this year as recently as your April presentation. Can you walk me through what has changed your expectation? And I guess given that these -- certainly, these wells have been in the pipeline for a little while. Why we don't have the appropriate rig available?

[Dana Coffield:]

We were considering using the slim holed rig that the ANH is using for their strat drilling in other parts of Colombia. And that's not available to us. And to use a conventional rig, we're not able to get the environmental permits to do that. It's a much larger footprint. It was actually a combination of 2 or 3. One is the rig availability, and the other is the environmental permitting. We're not able to get environmental permit this year for a conventional rig.

[David Dudlyke:]

Okay. But essentially, your expectation was that you would assume the ANH rig and that has proved unlikely this year.

[Dana Coffield:]

Yes.

[David Dudlyke:]

A question for Martin perhaps. You reported G&A of $13.6 million for the quarter, notwithstanding the fact that you've essentially taken over Petrolifera, but also there was some one-off costs, no doubt, with the acquisition. Can you provide some guidance as to what you think you can compress the combine G&A back down to on a run-forward basis?

[Martin Eden:]

We're still looking at about just over $9 a barrel for the year actually. That's our current estimate, $9.

[David Dudlyke:]

Okay. And then can you perhaps explain to me the $32 million write-down, the impairment for ceiling test in the Peru cost center? I'm trying to get my head around that. But if you can just at least explain where that stems from?

[Martin Eden:]

That comes from $15.6 million for the Kanatari well and we've also written off some seismic and area magnetic geographic survey on Blocks 122 and 128.

[David Dudlyke:]

Okay. So that speaks to not only the results for the well but also the I guess the switching of priorities away from those blocks to your other blocks within your portfolio. Okay. And last, if I may, Brillante, I'm looking at the presentation, how long a pipeline would you have to build from Brillante given the disappointing results in San Angel. You proposed to build the pipeline southeast down to the GGI pipeline. Is that still the case?

[Dana Coffield:]

There's 2 different pipeline options. Say it's 40 kilometers, same thing 50 -- I'm saying 40 to the southeast, to the GGI pipeline. Let's compromise, say, 50 kilometers. So what is your question?

[David Dudlyke:]

Essentially, what is the minimum scale of discovery? I see the reserve that you talked for Brillante but essentially, have you got enough to merit the building of a pipeline or do you need the second well to prove up some further results?

[Dana Coffield:]

I think that the 30 BCF is marginal, which I believe is about what we have proved at 3P around 110 BCF. Including prove up 70 or 80 BCF, we'll have it very robust. Is that good enough for you?

[Operator:]

Your next question is a follow-up from the line of Martin Molyneaux.

[Martin Molyneaux:]

Gentlemen, can you just walk us through this equity tax calculation that has resulted in the $8 million charge in the first quarter?

[Martin Eden:]

Yes. So, it's assessed on our equity value of our Colombia branches and whichever you want, so basically for the calculation of what our balance sheets were in our branches when we apply the 6.2% tax. As I mentioned, it's payable over 4 years. But for accounting purposes, we need to recognize it in the first quarter when we first calculated the tax.

[Martin Molyneaux:]

Okay. So 4 years ago, in the first quarter, you would have done the same thing?

[Martin Eden:]

That's my understanding, yes.

[Operator:]

Your next question is a follow-up from the line of Jaime Somerville.

[Jamie Somerville:]

My question's actually been answered already. Thanks.

[Operator:]

Gentlemen, there are not further questions at this time. Please continue.

[Dana Coffield:]

Thank you. Once again, I'd like to thank everyone for joining us today, and we look forward to speaking with you the next quarter to update you on our progress. So everyone, enjoy your week this week. Goodbye.