Gran Tierra Energy Inc.
Q1 2013 Earnings Call Transcript

Published: 6 May 2013

[Operator:]

Good afternoon, ladies and gentlemen, and welcome to Gran Tierra Energy's results conference call for the quarter ended March 31, 2013. My name is Tuanda, 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, Monday, May 6, 2013, at 4

[Dana Coffield:]

Thank you, Tuanda. Good afternoon, and thank you for joining us for Gran Tierra Energy's First Quarter 2013 Results Conference Call. With me today is Shane O' Leary, our Chief Operating Officer; and James Rozon, our Chief Financial Officer. This morning, we disseminated a press release that include a detailed financial information about the quarter. In addition, Gran Tierra Energy's 2013 report on Form 10-Q for the 3 months ending March 31, 2013 has been filed on EDGAR and SEDAR and will be available on our website at www.grantierra.com.I'm going to begin today by talking about some of the key developments for the quarter. James will discuss key aspects of this quarter's financial results. Shane will then take a few minutes to provide an operations update, and I will then return to provide a budget update and closing remarks. Gran Tierra Energy is pleased to start the year with a major new oil exploration well success in Peru, record levels of production and associated record revenue and funds flow from operations. Quarterly oil and natural gas production, net after royalty and adjusted for inventory changes, was 23,424 barrels of oil equivalent per day, an increase of 40% from the comparable period in 2012. Alternative transportation arrangements to minimize the impact of pipeline disruptions in Colombia, a decrease in oil inventory in Colombia and production from new wells in Colombia and Argentina all had a positive impact on production. Production before inventory adjustments in April averaged approximately 22,000 barrels of oil equivalent per day, net after royalty, affirming our pipeline disruption mitigation plans are fully operational. On the exploration front, in February 2013, we announced the results of the Bretaña Norte exploration well in Block 95. This discovery has the potential to add substantially to the growth of Gran Tierra Energy in the years to come. The 1,984 barrels of oil per day test of 18.5-degree API oil gravity far exceeded our expectations. Given this success, we nearly drilled a horizontal sidetrack well extension to the existing well and are in the process of preparing to test this extension. In addition, we have added a 2D seismic program over the discovery to this year's budget. This program will extend to the south, while we have another exploration prospect we look to further define for future exploration drilling. Concurrently, with all this, we are evaluating full-field development options and anticipate first long-term test production from the Bretaña Norte field in early 2014. With revenue of $205 million and funds flow from operations of $109 million in the quarter, our balance sheet continues to be strong. Cash and cash equivalents were $236 million at March 31, 2013. We remain debt-free, and we continue to expect to fund our capital programs with cash flow and cash on hand at current oil prices and production levels and potential periodic draws from our revolving credit facility, if needed. Now let me turn the call over to James Rozon to discuss the financial results. James?

[James Rozon:]

Thank you, Dana, and good afternoon, everyone. Our operational success last year has translated into another quarter of financial success, allowing us to retain a strong balance sheet to continue funding our growth strategy. Revenue and other income in the first quarter of 2013 was $205.4 million, a 32% increase from 2012 due to increased production, partially offset by decreased average realized oil prices. The average price received per barrel of oil decreased by 6% to $99.17 from $105.36 in 2012. During the first quarter of 2013, 28% of our oil and gas sales in Colombia were to a customer where the realized price is adjusted for trucking costs. The effect on the Colombian realized price was a reduction of approximately $5.10 per barrel to $103.08 per barrel as compared to delivering all of our Colombian oil through the OTA pipeline. Operating expenses in the first quarter of 2013 were $41 million or $19.46 per BOE compared with $24.5 million or $16.07 per BOE in 2012. The increase in operating expenses primarily occurred in Colombia, where there was a $13.5 million increase over the prior year. The increase in Colombia was mainly due to a change in sales point, resulting in OTA pipeline transportation costs now recorded as operating cost versus a reduction of revenue effective February 1, 2012, increased G&A allocations to operating cost and new wells with higher operating costs. The estimated net effect of OTA pipeline disruptions on Colombian transportation cost for the 3 months ended March 31, 2013 was neutral. The increased trucking costs to an alternative pipeline were mainly offset by the absence of OTA pipeline charges relating to both these volumes and the volumes sold at the Costayaco battery. The trucking costs associated with the volumes sold at the Costayaco battery were a reduction of the realized price rather than recorded as transportation expenses, with the $5.10 per BOE reduction of net realized price in Colombia as previously discussed. Depletion, depreciation, accretion and impairment, or DD&A, expenses in the first quarter of 2013 were $58.4 million compared with $60.4 million in 2012. DD&A expenses in 2012 were -- included a $20.2 million ceiling test impairment in our Brazil cost center relating to seismic and drilling costs on Block BM-CAL-10. On a per BOE basis, the depletion rate decreased by 30% to $27.71 from $39.62. The decrease was mainly due to the impairment charges of $13.26 per BOE in the comparable period in 2012. Increased costs in the depletable base were partially offset by increased reserves. General and administrative, or G&A, expense decreased by 28% to $11.4 million. Increased employee-related costs reflecting expanded operations were more than offset by increased recoveries and higher G&A allocations to operating expenses and capital projects in all business units. G&A expenses per BOE in the first quarter of 2013 of $5.42 were 48% lower compared with $10.44 in the comparable period in 2012. In the first quarter of 2013, the foreign exchange gain was $5.2 million, comprising a $6.7 million unrealized non-cash foreign exchange gain, offset by realized foreign exchange losses of $1.5 million. The foreign exchange gain was a result of a net monetary liability position in Colombia combined with the weakening of the Colombia peso; whereas, the foreign exchange losses resulted from a net monetary asset position in Argentina and the weakening of the Argentina peso. For the first quarter of 2012, there was a foreign exchange loss of $24.4 million, of which $21.4 million was an unrealized non-cash foreign exchange loss, as result of a net monetary liability position in Colombia combined with the strengthening of the Colombian peso. Other loss of $4.4 million in the first quarter of 2013 relates to a contingent loss accrued in connection with a legal dispute, where we received an adverse legal judgment within the quarter. We have filed an appeal against this judgment. We had net income in the first quarter of 2013 of $57.9 million compared with a loss of $0.3 million in the comparable period in 2012. In 2013, increased oil and natural gas sales, decreased DD&A and G&A expenses and a foreign exchange gain were partially offset by increased operating and income tax expenses and other losses. For the first quarter of 2013, funds flow from operations increased by 38% from $78.9 million to $108.6 million. The increase was primarily due to increased oil and natural gas sales, decreased G&A expenses and realized foreign exchange losses, partially offset by increased operating and income tax expenses. A reconciliation to net income is included in our first quarter 2013 earnings press release. Cash and cash equivalents were $235.9 million at March 31, 2013 compared with $212.6 million at December 31, 2012. The increase in cash and cash equivalents during 2013 was primarily the result of funds flow from operations of $108.6 million, partially offset by capital expenditures of $87.4 million. In summary, we remain financially strong. We expect that our 2013 capital program of $424 million will be funded from cash flow from operations, cash on hand and potential periodic draws from our revolving credit facility, if needed. That concludes my comments. I would now like to turn the call to Shane for an update on our 2013 capital plan and outlook. Shane?

[Shane P. O’Leary:]

Thank you, James. On the Chaza Block in Colombia, where we maintain a 100% working interest and operatorship, we continue the development of the Moqueta field in the Putumayo Basin. Moqueta-9 was spud on January 20, 2013 to test the northwest extent of the Moqueta field. It discovered hydrocarbons in a different fault block, separate from the main Moqueta oil accumulation. The T-Sandstone tested gas and the combined Caballos and U-Sandstone formations tested oil and water. These results, integrated with seismic and other wells drilled to date, indicate the well has defined the northern margin of the main Moqueta oil accumulation. The down-dip extent of the oil column to the west, south and east and the lateral extent of the structure to the east have not yet been defined by drilling, with this additional resource potential to be defined with our ongoing drilling campaign. Moqueta-10 has begun drilling. This well will be used as a water injection well to assist with pressure maintenance in the Moqueta field to support production growth from existing and future planned production wells. This well is being drilled to the far western flank of the field and may provide additional information on the down-dip extent of the oil column in the primary reservoirs in the main fault block, which has not yet been determined. This well will be followed by a Moqueta-11, which is planned to be a production well. The balance of this year will focus on increasing water injection for pressure support and increasing production capacity from the field. Once permits are in place, we can then direct our attention to appraising the eastern flank of the Moqueta structure, which remains unfilled. The Costayaco-18 development, also on the Chaza Block, is expected to be on production this month to assist in maintaining plateau production at the Costayaco Field. On our Guayuyaco Block, where we have a 70% working interest and operatorship, civil construction is ongoing on the Miraflor West-1 oil exploration well, which is expected to be spud in the second quarter of 2013. In the Llanos Basin, long-term testing of the Ramiriqui-1 well and the 2012 Ramiriqui oil discovery operated by CEPSA and where Gran Tierra has a working interest of 45% started on April 22, 2013, with current gross production of approximately 900 barrels of oil per day. Additional compression and unloading facilities are being constructed to handle associated gas production. In Peru, Gran Tierra Energy completed drilling in the Bretaña Norte 95-2-1 XD exploration well in Block 95. Log interpretations and MDT fluid and pressure sampling indicate the presence of an oil-bearing sandstone reservoir in the Vivian formation, with an approximate gross oil column thickness of 99 feet and 53 feet, net pay thickness. Laboratory analysis of the oil samples indicate the oil has a gravity of 18.5 degrees API. A drill stem test was conducted over a 29-foot interval. Approximately 1,170 barrels of oil per day was produced on natural flow without pumps for 19.65 hours with 0% water cut through a 46/64-inch choke. The choke size was then increased to a 64/64-inch, and oil flow increased to approximately to 1,984 barrels of oil per day on natural flow without pumps over a period of 1.5 hours with 0% water cut. The wellhead flowing pressure and temperature were increasing through the test, indicating that the formation was cleaning up and oil flow was increasing over the duration of the test. The test was successfully concluded when available crude oil storage capacity had been achieved. A 470-meter horizontal sidetrack extension of the well has now been drilled, encountering excellent reservoir quality with good oil staining. A short test is planned for May. Plans are ongoing to initiate long-term testing from this horizontal well, with production to be initiated within the year. In addition, a Preliminary Front End Engineering Design has been initiated for the Bretaña Norte field development to support reserves booking, with results expected before year end. Finally, a new 2D seismic acquisition program will be conducted in the second half of 2012 over [ph] the discovery in addition to further defining an independent exploration prospect to the south of Bretaña Norte. Our onshore exploration program in Brazil, specifically the horizontal multi-stage fracture stimulation drilling program in the Recôncavo Basin, is ongoing, with results of the program expected mid-year. In Argentina, plans are underway to drill a second horizontal multi-stage fracture stimulated well in the third quarter of 2012 after the successful production test of the PMN-1117 horizontal multi-stage fracture stimulated well in late 2012. The drilling program on the Puesto Morales Block was initiated earlier than planned, with 2 successful vertical development wells, PMN-1130 and PMN-1131, currently on production. We plan to replace 2 development wells originally planned for the second half of 2013, with the horizontal well into the Loma Montosa formation to further evaluate this play. Let me now hand it over to Dana for a capital -- for a brief capital spending update and concluding remarks.

[Dana Coffield:]

Thanks, Shane. So largely, due to the success experienced so far in 2013, we have increased Gran Tierra Energy's capital spending program for the year to $424 million from $363 million. The revised budget includes

[Operator:]

[Operator Instructions] Your first question comes from the line of George Toriola with UBS.

[George Toriola:]

I've got a couple of questions. The first is on Bretaña. What do you expect to learn from the short-term test? Could you sort of go through the key learnings that you expect from the short-term test?

[Dana Coffield:]

From the short-term test in -- coming in May, it will be a -- understand a little bit about the productivity of this portion of the reservoir that we've just drilled, understand a little bit about the pressure decline -- or the pressure decline and the pressure recovery in the reservoir, as a result of the test. So those will be the 2 main factors in the short test. And then, the long-term test, which we intend to initiate beginning of next year, will be more of the same, but over a longer duration.

[George Toriola:]

Okay. That's helpful. And then, in terms of field definition, what -- are you expecting to drill step out so -- for the appraisal wells between now and when you initiate the long-term test?

[Dana Coffield:]

No, we intend to release the rig, the current rig, after this short-term test. And then, we are planning now for an appraisal well to be drilled on a completely new location at the southern end of the structure late next year -- sometime in the second half of next year.

[George Toriola:]

Second half of '14?

[Dana Coffield:]

Yes.

[George Toriola:]

Okay. That's helpful. And then, maybe just in terms of operating costs, what -- can you sort of -- and I think you guys talked about the increase in operating costs and some reclassification of costs as well as the higher volumes. Now all of your current production volumes, are you -- how much of that is -- how much of that goes through the pipeline?

[Dana Coffield:]

Well, it all varies. The amount going by truck and amount going by pipeline varies. Some days, 100% of it is by pipeline. When the pipeline is down, the main pipeline, say, in Colombia we're talking about, then we have alternative pipeline transportation into Ecuador, and that is supplemented by trucking. So it's quite variable depending on the status of OTA.

[George Toriola:]

Okay. I guess, maybe, I should ask it differently. Going forward, what do you expect your per unit operating costs would be? What would you see as a more normalized type of operating cost per barrel?

[Dana Coffield:]

Well, normalized, I would just suggest what happened in the last quarter, first quarter of this year would be the normal cost given the current environment we're working in.

[George Toriola:]

Okay. And then, last question is just -- you continue to maintain your 20,000 barrels a day, net after royalties. And based on what April was, is that suggesting that you're forecasting for declines from here or you're just building contingencies that may arise out of the pipeline?

[Dana Coffield:]

Yes, the -- going forward, we're expecting -- well, we're still budgeting for 20,000 barrels a day, assuming the 10% contingency downtime. Now we have these mitigation programs in place that has been overcoming the downtime. So at this point in time, we're not changing our outlook. Although, obviously, for the last 4 months, we have been mitigating that downtime. So this is some of what we look at as the year evolves.

[Operator:]

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

[Nathan Piper:]

A few questions from my end. And first of all, on Peru, I'm trying to have another go at just assessing the potential of what you've already discovered. If you are going to proceed with the field study, clearly, you must have a vision of how big the field already is. And I know that you've highlighted a contingent resource number that was used prior to the wells being drilled that you just completed and tested successfully. I mean, is that a historic number now? Or what's the sensible way of thinking about the potential that you think you've already clarified and you'll put field study together for? And what's the upside from here?

[Dana Coffield:]

Well, I mean, we're confident of the commercial project here. The contingent resource numbers that we published were numbers from the original Amoco well drilled in mid-'70s, do not include numbers from the more recent Bretaña discoveries, Bretaña Norte. We found better reservoir quality than we expected, better oil quality than expected. So I think those numbers are somewhat outdated. They're conservative. And we're very aggressively moving forward to get more reflected reserves booked by year end.

[Nathan Piper:]

Well, what's the basis for your field study? What field size are you going to base your field study on?

[Dana Coffield:]

We can do several different field sizes. So there's going to be a range of different field sizes in the study.

[Nathan Piper:]

And you're not prepared to give that range anytime?

[Dana Coffield:]

Not right now, I guess.

[Nathan Piper:]

All right. And so, second question then. On Moqueta, just to understand the implications of Moqueta-9 results, I mean, there's been -- Dana, you've defined the northern extent as a nice way of saying -- well, potentially saying [indiscernible] high much more. And in the context of the GLJ reserves [indiscernible] Moqueta-9 results back up?

[Dana Coffield:]

I don't think it really impacts our GLJ reserves or year-end reserves at the end of last year. The reserves, they're really based on existing well data at that time. So we're still looking at, well, additional resource potential -- or additional reserve potential down-dip to the west, to the south and then eastern flank of the structures not yet defined by the drilling. We're not expecting any negative impact on the year end reserves from last year.

[Nathan Piper:]

Okay. So it's confirmational rather than additive. Is that fair?

[Dana Coffield:]

That's correct.

[Nathan Piper:]

Okay. And then last question, on Brazil, I think [indiscernible] the 14th and 15th [indiscernible] supposed to go on the 14th and 15th this month. Is that approximately the timing when we would hear more on the test results from Recôncavo Basin? I mean, I do know that the [indiscernible] keep picking up so you've got made commercial discoveries there -- or [indiscernible] next discovery there. But clearly the test rate, what's -- what are we waiting for? I mean, have you completed the operational work on that and just waiting for the right time to release the information, or are you still working on those wells?

[Dana Coffield:]

No, it's still early days with the wells. So the -- I don't think we'll be putting out news, I don't think, until we get the 3 wells drilled, frac-ed and then tested, and we're only halfway through that program. So I think, by the time we get the third well done, it will be in mid-year. So it's not just waiting for the [indiscernible].

[Nathan Piper:]

That fair enough. You'd rather just put them together because that's going to aggregate program that's relevant rather than individual wells?

[Dana Coffield:]

That's correct.

[Operator:]

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

[Matthew Portillo:]

Just a few quick questions for me. In terms of Costayaco, we continue to see production holding up quite well. I was just curious if you can give us an update on water injection and how you guys think about plateau production levels from here and maybe any color on timing of when we could potentially expect to see some of those production declines kicking in?

[Dana Coffield:]

We continue to ramp up the water injection at Costayaco. I think we're up to around 26,000 barrels a day. But I mean, ultimately, we're trying to get up to 40,000. So we're continuing, as part of our regular drilling campaign, to drill both water injection wells and production wells and are looking at some stimulation techniques on other wells to increase the injectivity of water, and we're building another pump station for water and treatment facility and so on. So water injection is continuing and continues to be very effective. We've always predicted Costayaco plateau would come off sometime. I think we're sort of looking into next year now. But we're not expecting to see any declines from Colombia because Moqueta continues to ramp up. And the only thing really standing in the way of increasing Moqueta production at this point, we have enough wells into the field now, is water injection. We have to get more water into the reservoir at Moqueta, and then we can increase production rates from that field. So this is this all going to happen in parallel, and we don't expect to see declines next year in Colombia.

[Matthew Portillo:]

And I guess, as we think about kind of the development well you guys just drilled, was that a booked reserve in terms of -- was that a well you planned to encounter oil in, or was that something you're drilling as a water injector and you found oil? I'm just trying to get a little more color on that?

[Dana Coffield:]

I don't expect to see any reserve increase. You're talking about Costayaco?

[Matthew Portillo:]

18.

[Dana Coffield:]

17 or 18? 18. No. I mean, that's part of the field. It's within the field boundary. And so, I wouldn't expect to see -- and there might be some minor adjustments, but nothing material.

[Matthew Portillo:]

Okay. And then, just with Moqueta, the structure. I think kind of in the blue sky scenario, previously, you'd kind of potentially thought of it as a 30- to 40-million barrel type structure and kind of the blue sky case. Has that picture changed at all with what you learned on Moqueta-9? Has that removed any of that upside, or do you still see the potential to move the resource size up over time?

[Dana Coffield:]

I don't think our numbers are quite as big as what you are quoting there, but, no. If you recall the Moqueta field structure, we were trying to prove up reserves underneath the major fault to the north. I wouldn’t say we completely condemned that concept, but it's much more complicated than we were expecting. And it's not something we would test again in the near term. We would wait, and we have other priorities for the field. So we -- as we said, we define the northern limit to the field, as we know it today, with the current drilling we've done.

[Shane P. O’Leary:]

But the other point is there's significant running room remaining potential on the eastern flank, which is yet to be drilled.

[Matthew Portillo:]

Great. And then, just on Moqueta, in terms of the production ramp-up, how should we think about, kind of, the plateau production levels you guys are envisioning under the current development plans, kind of, in 2014, 2015? I'm just trying to get a better sense of how should we be thinking about that production profile going forward.

[Dana Coffield:]

Well, we have a productive capacity right now to produce almost 5,000 barrels a day. But we're not there because we need to get more water injection going. So that's our priority for this year. If some of these higher reserve numbers are proven up as we go forward, we've thought about getting up as high as 70,000 barrels a day, but that's still conceptual. We still need to drill more wells in -- as Dana was talking about, in the eastern part of the field, in the southern part of the field. And we need to really define the limits of the reserve estimate before we can really talk about ultimate numbers.

[Matthew Portillo:]

And just my last question. On Llanos-22, you guys have just started up production. I think that's under a fairly constrained rate. You mentioned that you are looking at compression and some additional gas takeaway. How should we think about the production profile on that well? And are there any additional appraisal wells that you plan to drill this year or any exploration wells on the block? I'm just trying to get a sense of, kind of, the productive capacity from that area over the next 6 to 12 months.

[Dana Coffield:]

Well, we're currently flaring gas -- the associated gas, and we have a flaring restriction. I think we're around 1.3 million a day or something like that. What we're looking -- what we're trying to do is tie in to the Techion [ph] facility, and we're actually looking at a compressed natural gas trucking scenario, where we can get, in the short-term, volumes to their facility transported by truck, which would allow the operators, perhaps, to increase the volume from the current test. So that's ongoing, and it's something that can be done in the fairly short term, assuming everything goes well. Longer term, you'll recall that the well tested in excess of -- I think, it's around 2,500 barrels a day. So, yes, we are severely limiting the test volume right now. But there is a well planned for next year at the -- an appraisal well that we're nearing construction.

[Operator:]

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

[Neal Dingmann:]

I'm just wondering. Dana, you obviously -- a strategic question. Your cash position tends to be very positive and, in fact, growing a little bit. Just your thoughts as far as acquisitions. You currently obviously have a fair amount of acreage already. But then just your thoughts, number one, on sort of CapEx given that sizable cash position you have. And then, besides, I guess, CapEx, looking at what you think about dividends or repurchase or how else maybe you give back cash that way?

[Dana Coffield:]

Yes. So acquisitions, we're constantly on the lookout for acquisitions in different forms farm ins, asset acquisitions, corporate deals. But as you know, we have a very large land position and a very strong asset base that we're confident we can keep growing the company with. So for us, to do any kind of acquisition, it has to be extremely compelling. And we just don't see many compelling stories out there that we think could actually add value to assets or lands that are more attractive than our existing lands. So we continue looking, but it's tough to find something that we like more than our own existing acreage. Now you note our strong cash position, it's historically been strong. We are, I guess, on an ongoing basis, due to the dividends and other alternatives, due to the stock, but the reality is, given our success, given our growing capital demands, we think this money is best kept in reserve to invest in our existing lands. There's some major projects that are developing in Gran Tierra, and we want to be able to execute on those projects with timely fashion. So at the moment, our plan is to keep investing in the company.

[Neal Dingmann:]

Fair enough. And that is a great answer. And then, I'm just wondering, you mentioned about the large lease position that you have, Dana, but I was wondering, I guess, more specifically, where you're not quite as active in, I mean, you're starting to become more active in Peru. But just wondering, even if you say, look at Argentina, is there any issues there with holding leases for the remainder of this year?

[Dana Coffield:]

Well, in general, no. In general, all our leases do have expiries. So we do have undertaken a certain amount of work on our leases in a timely fashion. So I wouldn't say there is any significant lease [indiscernible] on any of our land. We are doing the work. Some of our contracts in Argentina, we are -- they do expire in 2015, 2016 timeframe. So we are renegotiating some more commitments on a few of those blocks to get a longer -- get extension to the periods that we hold that land.

[Neal Dingmann:]

Got it. And then, just lastly. I was wondering about -- with this position, what's your thoughts on hedges and having more hedges at this point?

[Dana Coffield:]

No, we have no hedges in place on any of our traction, and we don't have any plans to hedge.

[Operator:]

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

[David Popowich:]

You mentioned a couple of times that the Moqueta structure holds additional potential to the east. I'm just wondering when you think you'll be able to appraise this? And then probably a related question is, how many more wells do you have permitted at Moqueta right now?

[Dana Coffield:]

Yes, that's the challenge. Right now, we have 2 locations permitted, and we're doing all our drilling -- these 10 wells now that we drilled, we are drilling from these 2 individual locations. So we're drilling deviated wells, long ridge wells trying to define the edges of the field. What we're waiting for is global environmental permit, which will allow us to drill wells anywhere we want in the optimum locations, either as producers or appraisal wells or water injectors. Because the location of these 2 appraisal licenses that we're drilling from, we can't reach the eastern flank of the structure, eastern 1/3 of the structure. So we're waiting for this global environmental permit, then our current understanding is that it should get approved in the -- early in the first quarter of next year. So hopefully, we'll get that approved early next year. That will then allow us to begin lease construction and then undertake drilling through next year to finish the appraisal and initiate infill drilling.

[Operator:]

Your next question comes from the line of Ian Macqueen with Gran Tierra.

[Ian Macqueen:]

Actually, to follow up on Dave's question. As far as I understand, that global environmental permit is delayed, and I was expecting it might be late Q3 or early Q4. Is that correct?

[Dana Coffield:]

That was probably our most recent outlook. I mean, the reality is, when we made the discovery, we thought we would have it a year before and I'm expecting it. So there's been a series of questions and answers, back and forth. We have now fully satisfied all of their questions, so there's no more work to be done. We received official notification of this just a few weeks ago. So there's a, call it, definitive clock now ticking, which allows us to say early first quarter.

[Ian Macqueen:]

Okay. Good. My question really revolves around both Brazil and Peru. Obviously, a lot of excitement involved with both of those assets, also a lot of capital. What's your current thoughts on farming out -- I guess, part of the idea of farming out is to distribute risk, and the other thing is to distribute capital exposure to a partner. So what's your thoughts on either Bretaña or other assets in Peru as far as farm out goes and the same thing for Brazil?

[Dana Coffield:]

Particularly, when we look at the farm outs, we would typically bring in partners on exploration projects versus [indiscernible] projects. And that's not just to reduce risk, but just to reduce our capital exposure to risk -- reduce our capital risk. So -- and that's our general philosophy, is farm out exploration and not reserves for contingent resources, same with Bretaña. So we're probably always open to different options. So on all of our projects in the company, we look at different strategic initiatives. Bretaña has still relatively long time till we get to plateau production with a lot of capital upfront. So we might consider partners there at some point, but no definitive decisions have been made.

[Ian Macqueen:]

Okay. So Bretaña maybe, and the rest there -- you still have lots of acreage in Peru. Are you actively seeking any partners for that at this point?

[Dana Coffield:]

Most of our exploration acreage, we're open to having partners. So...

[Ian Macqueen:]

Okay. So open to the idea, but nothing definitive. And then, in Brazil, can you comment on that?

[Dana Coffield:]

We're not looking for partners on our land now.

[Ian Macqueen:]

Your next question comes from the line of Josef Schachter with Schachter Asset Management.

[Josef Schachter:]

Can you shed some light on the exploration side for the Moqueta deep and for the Miraflor West-1 well, the time of when they'll go, the depths that you're looking at and the size or price? Can you maybe shed some light on those?

[Dana Coffield:]

Yes. The Miraflor West day or the Miraflor East is -- should start growing a month from now. We're just finishing up the location, have not yet started the rig mobilization yet. But that will be drilled, probably a second quarter well. Moqueta deep will be later in the year. That's late third quarter or early fourth quarter. In terms of resource potential, these are sort of more typical Colombian-type prospect sizes, pinnings, 4, 5, 6 million barrels or so.

[Josef Schachter:]

And the depths there?

[Dana Coffield:]

Oh, depths. Miraflor West is 8,000 feet, I think. Moqueta deep, 6,000 or 7,000 feet. So they're not deep wells. They're not unusually deep.

[Operator:]

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

[Dana Coffield:]

All right. Well, I'd like to thank everyone for joining us today, and we look forward to updating you on our progress through the year. Thank you for your time.

[Operator:]

Thank you for joining in today's conference. That concludes the presentation. You may now disconnect, and have a great day.