Gran Tierra Energy Inc.
Q1 2012 Earnings Call Transcript

Published: 8 May 2012

[Operator:]

Good morning, ladies and gentlemen, and welcome to Gran Tierra Energy's Results Conference Call for the 3 months ended March 31, 2012. My name is Keith 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, Monday, May 7, 2012, at 1 p.m. Eastern Standard Time. Please be advised that in addition to historical information, certain comments made during this conference call, particularly those anticipating future financial performance, business prospects and overall operating strategies, constitute forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. Such statements may be identified by words such as anticipate, believe, estimate, expect, intend, predict and/or hope or other similar expressions. Such statements, which include estimated or forward-looking production and financial information or results are based on management’s current expectations and are subject to a number of factors and uncertainties which could cause actual results to differ materially from those described in the forward-looking statements. Listeners are urged to carefully review and consider the various disclosures made by Gran Tierra Energy in its reports filed with the Securities and Exchange Commission, including those risks set forth in Gran Tierra Energy's quarterly report on Form 10-Q filed with the SEC on May 7, 2012 and in its annual report on Form 10-K for the year ended December 31, 2011 filed with the Securities and Exchange Commission February 27, 2011 (sic) [2012] . If one or more of these risks or uncertainties materialize or if the underlying assumptions prove incorrect, Gran Tierra Energy’s actual results may differ 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 non-GAAP measures, funds flow from operations. The press release disseminated by Gran Tierra Energy this morning includes the reconciliation of this non-GAAP item with the company’s GAAP net income or loss, as well as information about why management believes this measure is useful in evaluating the company’s performance and is available on Gran Tierra Energy's website at 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. And I will now turn the conference call over to Mr. Dana Coffield, President and Chief Executive Officer of Gran Tierra Energy. Mr. Coffield, please go ahead.

[Dana Coffield:]

Thank you, Keith. Good morning and thank you for joining us for Gran Tierra's Energy's First Quarter 2012 Results Conference Call. With me today is James Rozon, our Chief Financial Officer. Shane O'Leary, our Chief Operating Officer, is not available today due to other commitments. This morning, we disseminated a press release that included detailed financial information about the quarter. In addition, Gran Tierra Energy's 2012 report on Form 10-Q for the 3 months ending March 31, 2012 has been filed on EDGAR and SEDAR and will be available on our website at www.grantierra.com. I'm going to begin today by talking about some of the key developments for the quarter. James will then take a few minutes to discuss key aspects of this quarter's financial results. I will then return to provide an operational overview and outlook and make a few closing remarks. Gran Tierra Energy is off to a very strong start with the drilling success so far in 2012. The Ramiriqui-1 oil exploration well in the Llanos Basin of Colombia reached total depth with good oil shows in the primary reservoir target in the first quarter. Subsequent to quarter end, we completed initial testing from a 20-foot interval in the Mirador formation. The interval had natural flow rates without pumps and restricted due to gas flaring limitations of up to 2,525 barrels of oil per day gross of 26 API gravity oil. We are currently evaluating options for testing additional reservoir intervals, potentially drilling an appraisal well, an implementation of an early production program on the Ramiriqui-1 exploration well. Another successful well, the Proa-2 appraisal well on our Argentine Surubi Block, was recently drilled. The well encountered approximately 31 meters of net pay. Production tests were performed on 2 intervals, resulting in a combined natural flow rate of 6,300 barrels of oil per day gross of 46 API oil. The well is currently on production at a constrained rate of approximately 2,000 barrels of oil per day gross while we analyze reservoir performance and additional transportation capacity. Gran Tierra Energy's production in the first quarter averaged 16,742 barrels of oil equivalent per day, net after royalty, comprised of 13,749 barrels of equivalent per day in Colombia and 2,856 barrels of oil per day equivalent in Argentina and 138 barrels of oil per day in Brazil. This is a 15% increase compared to the first quarter of 2011 due to additional production from the Petrolifera acquisition and production growth from Jilguero, Melero and Moqueta oil discoveries. Production from Colombia during the quarter was restricted due to 26 days of pipeline disruptions and a onetime reduction caused by a change in sales point of the crude oil sales contract, which resulted in increased inventory in the pipeline system, equivalent to approximately 1,040 barrels of oil equivalent per day net after royalty. Gran Tierra's production in April has grown further and is averaging approximately 20,700 barrels of oil equivalent per day net after royalty. Approximately 97% of this production is oil and natural gas liquid. In addition to successful drilling and production growth, we have strategically increased our working interest in our 4 onshore blocks in Brazil, so that we now will have a 100% working interest, subject to regulatory approval, in this very prospective acreage. We have recently finished drilling 2 development wells in an existing oil discovery and are advancing plans for our horizontal well campaign to be executed later this year. Financially, fund flow from operations of $78.9 million contributed to a cash and cash equivalents balance of $230.1 million at March 31, 2012. Our 2012 capital program has grown to $444 million and we continue to expect to fund this program from cash and cash flow at current oil prices and production levels. As before, Gran Tierra remains debt free. Now let me turn the call over to James Rozon to discuss the financial results. James?

[James Rozon:]

Thanks, Dana, and good morning, everyone. Financially, the first quarter of 2012 was another strong quarter for Gran Tierra Energy. Revenue and other income for the first quarter of 2012 was $156 million, a 27% increase from 2011 due to increased production and higher oil prices. The average price received per barrel of oil grew by 12% to $105.36 per barrel from $94.31 per barrel from the same period in 2011. Operating expenses for the first quarter of 2012 were $24.5 million, a 49% increase from the same period in 2011. Operating expenses on a barrel of oil equivalent basis were $16.07, an increase of 28% from the $12.52 in the same period in 2011. The increase in operating expenses included an increase of $3.7 million in Colombia, primarily due to OTA pipeline oil transportation cost now recorded as operating cost, and increased production at Moqueta and Jilguero with higher per BOE operating costs; $3.8 million in Argentina, primarily due to higher operating costs on the Petrolifera assets; and $0.6 million in Brazil, primarily due to new production. General and administrative expenses in the first quarter were $15.9 million, 17% higher than the $13.6 million for the same period in 2011, primarily due to a full quarter of Petrolifera G&A expenses and increased employee related costs reflecting the expanded operations in all business segments. G&A expenses per BOE were comparable with the first quarter in 2011 at $10.44 per BOE. Depletion, depreciation, accretion and impairment expense for the first quarter of 2012 decreased marginally to $60.4 million compared to $63.4 million for the same quarter in 2011. DD&A expenses for the first quarter of 2012 include a $20.2 million ceiling test impairment in Gran Tierra Energy's Brazil cost center. Included in the first quarter 2012 results is a foreign exchange loss of $24.4 million, of which $21.4 million was an unrealized non-cash foreign exchange loss on the translation of Colombian peso denominated current and deferred taxes to the U.S. dollar functional currency. For the comparable quarter in 2011, the foreign exchange loss was $5.2 million, of which $4.5 million was unrealized. The Colombian peso strengthened by 8% and 2% against the U.S. dollar in the first quarter of 2012 and 2011, respectively. Net loss was $0.3 million for the first quarter of 2012 compared with net income of $13.7 million or $0.05 per share, basic and diluted, for the comparable quarter in 2011. In the first quarter of 2012, increased oil and natural gas sales, due to increased production and higher realized oil prices, reduced impairment charges and no Colombian equity tax expense were more than offset by a $24.4 million foreign exchange loss, increased operating DD&A and G&A expenses and increased income taxes. Net income in the comparable quarter in 2011 included a gain on the acquisition of Petrolifera of $24.3 million and the Colombian equity tax expense of $8.1 million. Funds flow from operations in the first quarter was $78.9 million compared to $66.6 million in 2011. The 19% increase over the same period in the prior year was primarily the result of increased oil and natural gas sales and the absence of Colombian equity taxes, partially offset by increased operating and G&A expenses. Funds flow from operations is a non-GAAP measure based on net income or loss adjusted for depletion, depreciation, accretion and impairment, deferred taxes, stocks-based compensation, unrealized gain or loss on financial instruments, unrealized foreign exchange gains or losses, settlement of asset retirement obligations, equity taxes and a gain on acquisition. A reconciliation to net income or loss is included in our first quarter 2012 earnings press release. Our cash and cash equivalents were $230.1 million at March 31, 2012, compared to $351.7 million at December 31, 2011. The change in cash and cash equivalents during the first quarter of 2012 was primarily the result of funds flow from operations of $78.9 million and proceeds from issuance of common shares of $0.9 million, offset by an increase in net assets from operating activities of $92.4 million, $78 million of capital expenditures and a $31 million increase in restricted cash during the first quarter of 2012. In summary, Gran Tierra Energy remains financially strong with the expectation that our 2012 exploration and development capital program of $444 million is to be funded from cash flow from operations and cash on hand at current oil prices and production levels. That concludes my comments. I would now like to return the call to Dana for an update on Gran Tierra Energy's 2012 capital plan and outlook.

[Dana Coffield:]

All right. Thank you, James. Gran Tierra Energy continues to work on an ambitious 2012 capital program. This program has been revised to $444 million. This includes

[Operator:]

[Operator Instructions] And your first question is from the line of Neal Dingmann of SunTrust.

[Neal Dingmann:]

Dana, first question, just -- looked like you've got a fair amount of activity continued on Costyaco, just your thoughts on that field. How production should maintain for the remainder of the year going into next year?

[Dana Coffield:]

Yes, we do have a fair amount of activity ongoing. We've completed 1 new water injector well in the first quarter and we're going to drill 3 more wells in the field. Then in the balance of this year, another water injector and then 2 producers. And the water injection will help maintain reservoir pressure, the producers, obviously, to continue producing, the 2 areas that, according to our reservoir model, do not appear to have been drained effectively yet. So going forward, our intent is to maintain plateau production in the field, hopefully through this year and into next year, and then the initiation of production decline may start sometime next year.

[Neal Dingmann:]

Got it and then it looks like with the number of blocks in Argentina, I don't know if you, I guess if you kind of have that, sort of plans in place, so it maybe looks like it stepped up a little bit. Just wondering, your thoughts, if you kind of had to rank those, as far as activity, how material could we be talking on? A couple of those, like the Puesto Morales and a couple of those blocks, as well as just sort of overall in Argentina, your thoughts, with the geopolitical climate there now?

[Dana Coffield:]

Yes, sure. We're still very much, as part of our portfolio, focused on growing our business in Argentina. We expect to -- while we have stopped the production decline in the Puesto Morales field. Now we're starting implementing the water flood, start the infill drilling, so we're expecting to grow production from these fields well in the coming 6 months or so. We don't have a specific outlook or forecast for the production growth, but we could add maybe 1,000 barrels, 2,000 barrels a day gross, sort of that order of magnitude, with the additional work. In terms of the general political environment there, the news that's been in the press with the government of Argentina taking over the stakes of YPF's interest in -- or Repsol's interest in YPF. It's really focused entirely on that company and is not having an impact on us. We don't foresee an impact on us or the other companies in Argentina.

[Neal Dingmann:]

And then last 2, just on the OTA pipeline, and any -- you obviously had some downtime because of that. I guess, is that just going to be sort of, I guess nothing you can really do about that or are you -- are there any sort of workarounds that you'll continue to look into going forward?

[Dana Coffield:]

No, the pipeline interruptions are on the Ecopetrol owned and operated pipeline, so it's not our infrastructure. It's the pipeline that goes across the Andes mountains to the West Coast. And we've had these interruptions in the past, and I expect we'll continue having them in the future, but I can say the government, the federal government of Colombia, is very focused on maintaining the security and integrity of the pipeline systems and it'll continue to be a focus for the government going forward.

[Neal Dingmann:]

Okay, and then lastly, maybe for James, just on the FX. The hit, just this quarter, I don't know, is there anything, I guess going forward, can you hedge around that or is there anything you're doing to try to elude that going forward?

[James Rozon:]

Again, most of the foreign exchange amounts that we are realizing in our financial statements are actually non-cash amounts. So basically, we would not effect a hedge for non-cash foreign exchange gains or losses. Again, I think that's basically the only comment I have on that. That, that foreign exchange is associated with, mostly with current and deferred tax liabilities that are denominated in Colombian pesos and we therefore convert those at the balance sheet date of our reporting and those do generate, generally non-cash foreign exchange gains or losses.

[Operator:]

And your next question is from the line of Gavin Wylie with Scotia Capital.

[Gavin Wylie:]

Just a quick question around Moqueta, first off. Just looks like the production timelines there have slipped a little bit back further with the Q4 development plan. I just wanted to get a sense of -- are we essentially thinking, no real significant ramp up now until 2013. I know the plan was to kind of have it start to ramp up in the second half of the year, but volumes are likely to stay pretty marginal for the balance of the year, is that fair?

[Dana Coffield:]

There hasn't really been any slippage, no. We're producing around 2,000 to 3,000 barrels a day gross from the field now. And they'll certainly continue growing through the year. But the answer to your question is, we continue to expect the real ramp up to take place next year. I mean, it could start end of this year, but whether it's December or January or February, it's next year is when we expect to be ramping up production. We really need the 3D seismic finished and it has been acquired, it's currently being interpreted. We need to definitively define the oil water contact and have a well that can start injecting water and/or gas to maintain reservoir pressure before it's ramp up production. So this work has to be done this year, injection facilities in place at the end of the year. And then, we can start ramping up the production. So it will be, production growth, material production growth, would be taking place next year once the full development plan is done this year and we start getting the pressure support equipment in place late this year.

[Gavin Wylie:]

So would you think that your projected sales volume then for the year is going to be around that 2,000 mark on a gross level or does that -- some limitation there that would make it unavailable to do so?

[Dana Coffield:]

The order magnitude is at that level, yes.

[Gavin Wylie:]

Okay, perfect. And then just on Ramiriqui, just I wanted to chat there a little bit. If there was any update on any sort of timing of future development wells or if the operator subset has given you any indication of what the future program might look like?

[Dana Coffield:]

No, in fact, we're having those meetings literally real-time as we speak, last week, this week, next week. We're having meetings talking about appraisal well, when and where to drill an appraisal well, talking about designing its long-term test, the first production, different options around that, how we're going to handle the gas. So all of that is happening real-time, there will probably be another, say a couple of months, before we have a plan in place.

[Operator:]

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

[Alexander Klein:]

Dana, just wanted to focus a little on Brazil. So I've got a couple of questions here and I'm just wondering if you can give us a sense of when you expect the ANP to approve the acquisition of the 30% of the 4 blocks on the Recôncavo Basin.

[Dana Coffield:]

Within a few months.

[Alexander Klein:]

And then, further to that, I'm wondering if you could just elaborate on the field development plan that you're working out for that discovery and give us a sense of how many wells you might be drilling and what kind of plateau production we might expect and when?

[Dana Coffield:]

We've drilled 2 wells, 2 development wells, and depending on how the -- when the -- there's 2 reservoirs, we've been producing from 1 reservoir from the discovery well. So we'll start the production from these next 2 wells in June, July timeframe. And then from that production history, we'll then know whether or not we need more wells and how many more wells. So it takes some time to hopefully decide that. So currently, our plan is not to drill any more development wells in the discovery. There may perhaps be one more location that could be drilled, but we won't know that until we get more production history.

[Alexander Klein:]

So you're probably looking at doing something early 2013 after you've had a chance to review production history? Is that...

[Dana Coffield:]

Yes, yes, there wouldn't be another well this year. If there would be another well, it would be next year.

[Alexander Klein:]

And just given the first well, you've got production coming out of one well right now and I know its production is down about 41% since Q3 '11. Is that the kind of decline we should expect on these wells or are there other issues at play here?

[Dana Coffield:]

No, in fact we're essentially getting no decline, I think it's fair to say. We did have another issue, the oil processing facility where we were sailing a crew to broke down or had maintenance problems. And we had increasing salt content or had some salt in our oil, so we couldn't sell it elsewhere. So part of our increased capital program in Brazil was, I think, $7 million to process our crude on location to take the salt out and that will give us more flexibility in selling our crude. So the reduced production was due to inability to sell the crude to our supplier and not related to the reservoir.

[Alexander Klein:]

Okay. Well, that's good news. And then finally, just moving back to Colombia, I just wondered if you could remind us what kind of resource potential you're looking at with regard to La Vega Este-1. What kind of target size are you going after here? What's the potential?

[Dana Coffield:]

We haven't given specific guidance on individual prospects, but the mean of the discoveries on the trend or in the [indiscernible] Colombia mean, which is 1 million to 4 million barrels gross recoverable.

[Operator:]

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

[Jamie Somerville:]

Just a follow-up on Gavin's questions on Ramiriqui. I'm just wondering if taking a step back, if you can talk about additional prospectivity on the block if it was at all relevant to your original decision to farm into the block or whether it was all about the first prospect to be drilled and whether the discovery of those other things, do you de-risk other prospects that might be on the block?

[Dana Coffield:]

Yes, sure. It was a very attractive prospect, which drove the farm in, but the other attraction was it had running room. So there are other prospects and leads on the block. Some of the leads, well leads do require more seismic to convert them into drillable prospects. There are certainly additional exploration prospects independent of this to be drilled and that was one of the real attractions to the block. So with the successful discovery at Ramiriqui, that de-risks the other prospects, for 2 reasons. One, we now know that the reservoir has porosity improvability. These tend to be very deep sandstone reservoirs. So now we know the reservoirs have porosity improvability. And then we also know that there's oil there, versus say, water or gas. One of the risks of predrilling was, had oil migrated into the structures, and the other is, is it gas versus oil. So we've de-risked 2 of the components and so it doesn't affect the sizes of the other prospects but certainly, increases the chance of success.

[Jamie Somerville:]

Apologies, but I'm going to focus on a couple of relatively non-core operations. You've increased facility costs for the Garibay Block, just wondering if you could explain what's happening there. Roughly how much you're producing and why costs are going up?

[Dana Coffield:]

Let's see. Off the top of my head, I can't remember what the current production level is.

[Jamie Somerville:]

Are you expecting a ramp up in production at all?

[Dana Coffield:]

I'm sorry?

[Jamie Somerville:]

Are you expecting a ramp up in production at all?

[Dana Coffield:]

No. It's pretty much stable where it is now. The exact number, I can't remember what it is. It's just a, there's no single, large material cause of the increase. It's a lots of little things around them, trucking and transportation.

[Jamie Somerville:]

The other non-core operation I wanted to ask about was Argentina. And on the -- you've shifted some exploration drilling on the eastern blocks, I think you originally had 2 wells on Rinconada and you've now shifted one to the southern block. I was just wondering if there's anything -- you highlight the fact that the next well is to be targeting a play that is similar to a discovery on the Rinconada Norte Block, I'm wondering if there's anything from you that you're seeing, that is causing you to change your plan in that area?

[Dana Coffield:]

It's really just the -- well, since the recent discoveries, we've re-mapped the seismic, so it's just a question of -- well, the recent discovery de-risked some of the geology, so we've re-evaluated the prospect of the portfolio, and changed the focus because of the risk-reward of the prospects.

[Operator:]

Your next question is from the line of Justin Anderson with Salman Partners.

[Justin Anderson:]

Just have a question about Ramiriqui, do you have preliminary estimate for a range of acreage for the structure?

[Dana Coffield:]

No. Well, we do, but we haven't released any information on it.

[Justin Anderson:]

Okay, and do have an estimate of the recovery rate you might expect?.

[Dana Coffield:]

The recovery factor or the production rates?

[Justin Anderson:]

The recovery factor.

[Dana Coffield:]

There's a range, but again, I don't know what they are.

[Operator:]

Your next question is from the line of Caio Carvalhal with JPMorgan.

[Caio M. Carvalhal:]

I want to understand, I have 2 topics here to question. First of all, on production. I understand that production in this quarter came below expectation pretty much due to this problem in transportation. But it raised my attention, what you mentioned, like a few minutes ago, the production level you are running, if I understood correct, you mentioned you have in April a production level of 20,700 barrels of oil per day net after royalties, is that right?

[Dana Coffield:]

That's correct.

[Caio M. Carvalhal:]

It's a little higher than I was expecting for the second quarter. Are we seeing a higher increase in the production than you were previously expecting or this is pretty much what you was originally expecting for April?

[Dana Coffield:]

This is pretty much what we were expecting, for the, I'll say second quarter. We expect to be ramping up through first quarter into second quarter. And so we expect to be able to maintain this current production level through the balance of the year. Of course, with the intent to average between 20,000 and 21,000 barrels a day.

[Caio M. Carvalhal:]

Yes, that's right. Because that was the average I had for the year, 20,000 - 21,000. And if you're actually already in this range by April, I think we might have the risk to see some higher production than originally thought, a little higher than the range of 20,000 - 21,000. Is that a right assumption or no, we should expect this, the April level to continue [indiscernible] ramping up?

[Dana Coffield:]

We expect April level more or less to continue. So we'll stay with it. We're still essentially planning on meeting our guidance. So there's no change to our guidance.

[Caio M. Carvalhal:]

That's great. And another question, it's on the -- it's more an accounting question. When I look to the income tax you paid in this first Q. I understand the reason why the increase in the income tax was pretty much due to the higher production. However, when I look in terms of tax paid on a per barrel basis, right? I see that you spent most of 2011 running on something like $17, maybe sometimes down to $13 per barrel of tax paid. And this quarter, we went higher than $20, so it seems to me that even understand that the income tax was due to the higher production, there seems to have some snowball effect here. Has anything differently happened with the tax income this quarter or is this a new trend going forward because of the new production level? How can I reconcile and update my projections for the rest of the year based upon the volume of income tax expense this quarter?

[James Rozon:]

I'll take this question. So basically, our income tax is driven by the taxable income calculated, determined for our Colombian operations. So again, basically the taxable rate in Colombia is 33%. And that amount of income that we have, which we report for accounting purposes, is of course, would be adjusted for items that would not be deductible for Colombian tax purposes, such as unrealized foreign exchange losses, nondeductible royalties and other non-cash items. And of course, the depletion determined for tax purposes is different than that determined for accounting purposes. So again, in terms of trying to model our taxes, not an easy thing to do going forward because many events could affect it, but again, it's important to look strictly at our Colombian tax situation in order to try and determine what our tax profile would look like going forward.

[Caio M. Carvalhal:]

Okay, great. And I really apologize, but if you allow me just a very quick final question here. When you mentioned about the CapEx plan to Brazil, you mentioned that you increased it in about $50 million and one of the reasons behind it is the acquisition of the 30% remaining working interest in the onshore blocks. But I understand this acquisition has always been in the company, it's record [ph], right? So I mean, you were considering to acquire the remaining 30%, but didn't put the CapEx for that? Is that was the change, or something else happened? Because in my mind, this remaining 30% was already in the company's plan to acquire, right?

[Dana Coffield:]

It wasn't always. But our interest grew as we continued studying the block and then Alvorada decided that they were prepared to sell. So this additional interest wasn't available originally when we entered the block. It became available, we liked it, so we did the additional acquisition. I'm not sure if that answers your question.

[Operator:]

[Operator Instructions] And your next question is from the line of Matt Portillo with Tudor, Pickering, Holt.

[Matthew Portillo:]

Just a quick question for me on Ramiriqui. I wanted to see if you could provide any additional information on the trapping of the structure here, because it's against the fault. And then a follow-up to that, in terms of the follow-on prospects, I think a previous question had been asked on the de-risking. I guess if we're thinking about it from a geological perspective on the additional prospects on the block, are there any trends that we should be thinking about that have been de-risked with this primarily well down in the original structure here. And then lastly, I'm not sure if you can provide the information or not, just curious, in terms of when you log the well, what sort of kind of porosity ranges you were seeing, because obviously they did seem to have a very solid flow rate on the constrained choke?

[Dana Coffield:]

Yes, sure. We're not entirely sure that -- well, the reservoirs are consistent with the basin or is it that the play trend along strike, it's sandstone reservoirs and they're encased within a, or trapped within a, anticline with a reverse fault on one flank. We're just on the edge of the foothills trend which is where all the other big fields are on that trend. The oil column we encountered was within, call it a 4 way dip closure, but we did not encounter the oil water contact, so we don't know if further down dip, there is a fault seal element to the trap. So that's yet to be determined. But as far as specific reservoir data or characterization or areas and such, we haven't released any technical data yet. In fact, a lot of that technical data is still under evaluation. But it's the same play type that's been proven for many years on this trend in the foothills of the Llanos Basin.

[Matthew Portillo:]

Great. And then just one quick follow-up question, different region for you guys from an operating perspective. I guess on Block 95, can you give us an updated idea on maybe where you guys are budgeting or [indiscernible] the well there? And then potentially any plans for some of your bigger blocks within the region and the potential to bring in additional partners at some point?

[Dana Coffield:]

On the Block 95 well, we're looking at around $10 million to build a platform there, these are gross costs, and the order of magnitude around $30 million for drilling the well. And then with that, well the construction work has already begun. And then the drilling, we expect to begin, as I said, in the fourth quarter of this year, some of that spending may slip into early first quarter of next year. But the intent right now is try to get it done this year. Now in Block 107, we permitted several locations, but we've chosen a location, we're beginning the design of the location, the rig tender process for that, so there will be some early spending or some spending on that this year, but the actual drilling won't take place until next year. In the plan, it's to start drilling to the plates [ph] in the first half of next year. I don't have an actual budget number for you yet because we don't have a final budget number internally. And then we haven't made any decisions one way or another around partners. That's a possibility, to have a partner on the block. At this time, we have a 100% interest and have not made a decision which way we'll go.

[Operator:]

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

[Dana Coffield:]

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