Gran Tierra Energy Inc.
Q3 2013 Earnings Call Transcript

Published: 13 Nov 2013

[Operator:]

Good afternoon, ladies and gentlemen, and welcome to the Gran Tierra Energy's results conference call for the quarter ended September 30, 2013. My name is Crystal, and I will be your coordinator for today. [Operator Instructions] I would like to remind everyone that this conference is being webcast and recorded today, Tuesday, November 12, 2013, at 4

[Dana Coffield:]

Thank you, Crystal. Good afternoon, and thank you for joining us for Gran Tierra Energy's third quarter 2013 results conference call. With me today is Shane O' Leary, our Chief Operating Officer; and James Rozon, our Chief Financial Officer. Yesterday evening, we disseminated a press release that included detailed financial information about the quarter. In addition, Gran Tierra Energy's 2013 report on Form 10-Q for the 3 months ended September 30, 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; and Shane will then take a few minutes to provide an operations update. I will then return to provide a budget update and closing remarks. Gran Tierra Energy has just delivered another strong quarter of production. Quarterly oil and gas -- quarterly oil and natural gas production net after royalty and adjusted for inventory changes was 21,978 barrels of oil equivalent per day, an increase of 13% from the comparable period in 2012. Before inventory adjustments, production in October 2013 averaged approximately 21,000 barrels of oil equivalent per day net after royalty. Production for the third quarter of 2013 net expectation is due to continued successful execution of measures to mitigate the impact of disruptions on the OTA pipeline in Colombia. In addition, in Colombia, production from new wells had a positive impact in the third quarter. As a result, Gran Tierra Energy anticipates 2013 average production to range between 21,500 and 22,500 BOEs per day net after royalty before adjustment for inventory changes, an increase from the company's prior productions of 21,000 to 22,000 barrels of oil equivalent per day net after royalty. This is a second time the company has increased its production guidance in 2013. Approximately 97% of this production consist of light oil and it balances natural gas. Revenue and other income for the quarter was $190 million, a 12% increase over the period -- comparable period in 2012. Net income was $33 million compared with net income of $45 million in the comparable period in 2012. Funds flow from operations increased to $285 million for the 9 months ended September 30, 2013, from $207 million in the comparable period in 2012. Cash and cash equivalents were $353 million at September 30, 2013, compared to $213 million at December 31, 2012. As before, we remain debt-free. Now operational highlights for the quarter include the following

[James Rozon:]

Thanks, Dana, and good afternoon, everyone. Our operational success 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 third quarter of 2013 was $190 million, a 12% 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 2% to $95.28 from $96.75 in 2012. During the third quarter of 2013, 38% of our oil and gas volumes sold in Colombia were to a customer where the realized price is adjusted for trucking costs related to a 1,500 kilometer route. The effect on the Colombian realized oil price was a reduction of approximately $7.61 per barrel to $96.72 per barrel as compared to delivering all of our Colombian oil produced in the Putumayo Basin through the OTA pipeline. Operating expenses in third quarter of 2013 were consistent with the corresponding period in 2012 at $36 million. The effect of decreased operating cost per BOE was offset by increased production. On a per BOE basis, operating expenses decreased by 13% to $17.60 from $20.24 in 2012. Operating expenses per BOE decreased in 2013, primarily due to OTA transportation costs and other trucking costs not incurred for those volumes subject to alternative transportation arrangements. For these volumes, ownership is transferred at the wellhead and the associated transportation paid by the purchaser is netted to arrive at a realized price. The estimated net effect on OTA pipeline disruptions on Colombian transportation costs for the 3 months ended September 30, 2013, was a savings of $2.02 per BOE. Depletion, depreciation, accretion and impairment, or DD&A, expenses in the third quarter of 2013 were $59 million compared to $45 million in 2012. On a per BOE basis, the depletion rate increased by 16% to $29.12 from $25.12 due to increased costs in the depletable base, only partially offset by increased reserves. General and administrative, or G&A, expenses increased by 14% to $15 million. Increased employee-related costs reflecting expanded operations and withholding tax on intercompany charges were partially offset by higher G&A allocations to operating expenses and capital projects within the business units. G&A expenses per BOE in the third quarter of 2013 of $7.26 were 1% higher compared with $7.19 from the comparable period in 2012. In the third quarter of 2013, the foreign exchange loss was $2 million, comprising a $2 million unrealized noncash foreign exchange loss and minor realized foreign exchange losses. The unrealized foreign exchange loss was a result of a nonmonetary -- net monetary liability position in Colombia combined with the strengthening of the Colombian peso. For the third quarter of 2012, there was a foreign exchange gain of $1 million, comprising a $2 million unrealized noncash foreign exchange gain and a realized foreign exchange loss of $1 million. We had net income in the third quarter of 2013 of $33 million compared to $45 million in the comparable period in 2012. In 2013, increased oil and natural gas sales were partially offset by increased DD&A, G&A and income tax expenses and foreign exchange losses. For the third quarter of 2013, funds flow from operations decreased by 6% from $90 million to $85 million. The decrease was primarily due to increased oil and natural gas sales, being more than offset by increased G&A and income tax expenses. A reconciliation to net income is included in our third quarter 2013 earnings press release. Cash and cash equivalents were $353 million at September 30, 2013, compared with $213 million at December 31, 2012. The increase in cash and cash equivalents during the 9 months ended September 30, 2013, was primarily the result of funds flow from operations of $285 million, a $64 million change in assets and liabilities from operating activities, partially offset by capital expenditures, net of proceeds from oil and gas properties, of $208 million. In summary, we remain financially strong. We expect that our 2013 capital program of $420 million will be funded from cash and cash flow from operations. That concludes my comments. I would now like to turn the call to Shane for an update of our 2013 capital plan and outlook. Shane?

[Shane P. O’Leary:]

Thank you, James. The nearest term growth opportunity for Gran Tierra Energy continues to be the Moqueta field. Moqueta-11 appraisal well encountered oil in the T-Sandstone and Caballos formations. The T-Sandstone formation was tested at an average rate of 802 barrels of oil per day of 27 degree API oil with a 0.3% water cut. The underlying Caballos formation was tested at an average rate of 756 barrels of oil per day of 27 degree API oil with a 0.3% water cut. The top of the Villeta T-Sandstone is approximately 290 feet lower than the Moqueta-11 well compared to the lowest known oil encountered in the field at Moqueta-7, suggesting the oil column is 290 feet thicker than previously defined. The gross oil column in the Villeta T-Sandstone has now grown to 755 feet and the gross oil column in the underlying Caballos reservoir has now grown to 960 feet. Results to date indicate additional oil potentially exists further down the flank of the Moqueta structure. As a result, 3 new appraisal wells have been added to the 2013 Moqueta work program. The Moqueta-12 appraisal well began drilling on September 23, 2013, and is targeting a reservoir that is further south in a previously untested block approximately 270 feet down dip of the lowest known oil encountered at Moqueta-11. Once evaluated, a sidetrack to the Moqueta-12 will then be drilled, with the latter intended to be completed as a water injector for reservoir pressure support in the main field. This well is drilling ahead, with initial results expected in November. Gran Tierra Energy intends to drill 2 additional wells adjacent to the Moqueta field before year end. The Corunta-1 well spud on November 5 and is drilling in a northeast direction from the Costayaco-17 well pad, targeting what is believed to be a down-thrown fault block extension west of the Moqueta field. The Zapotero-1 well is expected to be spud in December and target the southern -- the southeastern portion of the Moqueta structure. Gran Tierra Energy continues to anticipate receiving the Moqueta global environmental climate in the first quarter of 2014, which will enable the company to pursue delineation of the northeast portion of the Moqueta structure later that year, in addition to more development wells to continue growing production. Moving to the Guayuyaco Block. We expect to spud the Miraflor West-1 exploration well, targeting the same Cretaceous sandstone reservoirs encountered at the Costayaco and Moqueta oil fields in November 2013. In the Llanos Basin, we continue drilling the Mayalito-1 exploration well and initiated 2D seismic on the Cauca-7 Block and continued 3D seismic on the Putumayo-1 Block. We also plan to acquire 2D seismic on the Cauca-6, Piedemonte Sur Blocks and 3D seismic on the Putumayo-1 Block. Facilities work is also planned on the Chaza, Garibay and Llanos-22 Blocks. In Argentina, during the third quarter of 2013, we spud the PMN-1135 well, the second horizontal multi-stage fracture-stimulated well in this new play. Due to a blockade by a landowner, drilling operations were suspended and discussions continue to resolve the dispute. Our planned work program for the remainder of 2013 in Argentina includes workovers on existing wells and facilities work on the El Chivil block. Moving to Peru. During the third quarter, Gran Tierra Energy completed the preliminary Front End Engineering Design study for the development of Block 95's Bretaña field and initiated a 2D seismic program to provide a more detailed map of the Bretaña structure, along with maturing separate independent exploration leads on the block. On Block 107, we continue to work to obtain the necessary environmental and social permit for future seismic programs. Our planned work program in Peru for the remainder of 2013 includes completing the infill seismic on the Bretaña Norte field and on another identified lead on Block 95, further planning for the Bretaña Norte field development and continued work to obtain the necessary environmental and social permits for future drilling activities and seismic programs on this block. Additionally, we plan to commence environmental impact assessments on Block 107, Block 133, Block 123 and Block 129. We continue to work towards booking reserves on the Bretaña structure at year-end 2013 and initiate long-term testing from the Bretaña Norte well in mid-2014. In Brazil, during the third quarter, we drilled an exploration well on Block 155. The GTE-8-BA exploration well is a deviated well targeting the Gomo shale oil interval. Gran Tierra Energy met its primary objective which was to cut and retrieve core from the target interval. 144 feet of core was successfully retrieved for detailed special core analysis studies to gain critical information regarding the oil shale play. The wellbore is currently suspended awaiting fracture stimulation which is planned for mid-November. We also drilled the 440-foot horizontal sidetracked oil exploration well from the GTE-7-BA wellbore, also targeting the Gomo shale oil interval. The wellbore is currently suspended awaiting fracture stimulation which is planned for early December. On Block 129, we are preparing to re-enter and isolate the final 2 fracture stages at the GTA-6-BA well prior to retesting the Gomo shale interval. The micro-seismic data acquired during the fracture stimulation at GTE-6 suggested that the final 2 fracture stages had greater fracture heights than expected and inadvertently frac-ed into a lower saline water-bearing zone. During the third quarter of 2013, we received a net payment of $54 million before income taxes from a third party in connection with the termination of a farm-in agreement in the Recôncavo Basin relating to Block 129, 142, 155 and 224. The payment was recorded in Gran Tierra's third quarter 2013 results as a credit to its capital pool and an associated income tax expense. We retain 100% working interest in these blocks. Our planned work programs for the remainder of 2013 in Brazil includes fracture stimulation on GTE 7 and 8 wells in Block 155, additional completion work on the GTE 6 well on Block 129 and the GTE 3 and GTE 4 producing wells in Guachiria field. We also plan to perform facilities and pipeline work on Block 155. I'll now hand it over to Dana for a brief capital spending update and concluding remarks.

[Dana Coffield:]

All right. Thanks, Shane. Gran Tierra Energy's planned capital program for its exploration and production operations in Colombia, Brazil, Peru and Argentina for 2013 has been revised to $420 million from $454 million. This includes $218 million for Colombia, $89 million for Brazil, $25 million for Argentina and $87 million for Peru and $1 million associated with corporate activities. The majority of our decrease on our capital spending is due to the deferral of the following projects to 2014

[Operator:]

[Operator Instructions] Our first question comes from the line of Nathan Piper with RBC Capital Markets.

[Nathan Piper:]

A few quick questions for me, if I may. First of all, on realizations and access to the OTA pipeline. What do you think is a good long-term average, or how long you think you're going to be able to access the OTA pipeline? And is your limited access to pipeline really a result of attacks and disruptions, or is it because the pipeline is not being repaired quickly enough? Could you just give a little bit of color on how you're accessing the pipeline and how you should consider it going forward?

[Dana Coffield:]

Well, it's hard to make inflations going forward. We continue to use contingency based on, say, last 6 months or a year results. The pipeline has been down for different reasons, primarily due to bombings, but also like there was 1 or 2 landslides this year. There has been regular repairs on the line with each event. So we kind of look at, say, at the trailing 6-month average, perhaps, to give us a view on forward utilization of the pipeline. But we are using it regularly when it is up and running.

[Nathan Piper:]

Okay, but you aren't seeing any improvements through the peace process? You're seeing disruptions of about relatively similar rate you have over the last couple of years?

[Dana Coffield:]

Similar rates as, I'd say, the last year, yes.

[Nathan Piper:]

Okay. Then another quick one on CapEx. Do you think you're still going to be able to meet the $420 million revised CapEx numbers, or is there a chance that some of the other projects or other expenditures slip into next year as well?

[Dana Coffield:]

We're more or less on track to meet the revised numbers.

[Nathan Piper:]

Great. And then last one on Brazil. What's the implication -- or what did the third party, the unannounced third party, not like that they were prepared to pay you $50 million to walk away? What's the implication from that payment you received?

[Dana Coffield:]

I can't really comment on their decision process, other than the fact that they chose not to proceed with the farm-out -- or farm-in, in their case. So I can't comment on their reasonings behind it. The implications, of course, is we got a significant amount of our drilling paid for.

[Operator:]

Our next question will come from the line of Matt Portillo with TPH.

[Matthew Portillo:]

Just wanted to see if we could get maybe an update on how you guys are thinking about some of the incremental prospectivity around your Putumayo Basin assets. I know that you've been really focusing on the Chaza Block, in particular with the Moqueta and Costayaco. But maybe just getting a bigger picture update on how your seismic program has progressed in the area and maybe a little bit more about the prospectivity heading into 2014 in terms of some of your drilling plans there.

[Dana Coffield:]

Yes. We are -- as Shane just said about to drill another exploration well called the Miraflor West-1 on that trend. As you know, we have a huge land position on that forward trend from Chaza going on down west right almost to the Ecuador border. The development of that exploration trends is slow due to the long time it's taken to get permits for our seismic programs. Having said that, we have shot new seismic and we are shooting new seismic. And we are currently working on our work program budget for next year, 2014. And we do expect to be drilling several exploration wells on that trend next year. So it is moving forward. We will be doing more exploration drilling on that trend. It has been slow, the turn of these prospects over the last couple of years because of permitting delays. But we are making progress, and we will see more wells drilled next year.

[Matthew Portillo:]

Great. And then just a question in regards to Moqueta, within Moqueta-11 well under your belt and kind of the continued increase to the potential growth oil column here. I was hoping that you may be able to put a little bit more context around what that well means in terms of the resource potential and maybe, specifically, as we kind of reference the 3P resource number that has been previously published at about 27 million barrels, what have we learned so far through the drilling program this year? And how does that kind of affect your development plans as we head into 2014 with kind of the oil in place or recoverable resources that you guys are looking at for the field?

[Dana Coffield:]

The resources is going up, the recoverable resource. We've drilled several wells since the year-end reserve report last year. Those wells had found more oils in the aerial extent of the -- outside the, say, the 3P area last year. And we also found more oil deeper in this section than the reserves that were booked at the end of last year. So the resource is going up. We will have the -- we're planning of having the reserve update, to revise 1P, 2P and 3P numbers early February, early next year, on the normal reserve -- corporate reserve update schedule. In terms of the impact on us in developing the field is we still are waiting for the global environmental permit, which we also expect in the first quarter of next year. This will allow us to be more aggressive, more efficient in drilling our development wells, our water injection wells and more efficiently developing the field. So it's quite a bit more work to be done. We're confident that the resource is growing, and we'll have more clarity on what that new resource numbers are in early February next year.

[Matthew Portillo:]

Great. And then just last question for me. I guess as you guys think about that kind of resource number, somewhere above the 3P number that's been previously kind of talked about, how does that affect your expectations around plateau production, I know that you're managing reservoir pressure as you look at field development here. But how are you guys thinking about maybe a range on potential peak production at Moqueta with what you know today?

[Dana Coffield:]

We don't have a real guidance yet on the plateau production in the field because we actually don't know what the reserves are yet. Haven't yet found our contact. We're confident we'll be growing production next year and into the following year, so 2014 and 2015. I think, assuming we get this global permit first quarter next year, I expect we'll probably hit the plateau production in 2015. But at what level and for how many years we can maintain that, it's still early days.

[Operator:]

Our next question will come from the line of Pedro Medeiros with Citibank.

[Pedro Medeiros:]

I have a few questions actually. They're more like checkups. The first thing is the increase on the G&A expenses from an increase in withholding taxes in Brazil. Is that a recurring event or not? And the second checkup is actually on the production task of Ramiriqui-1 in Colombia. Is that still producing? What was its contribution to the third quarter results? Lastly, when I look at your budget program for 2014, is the $14 million from your acquisitions already including any potential participating to Brazil's upcoming bid -12? Do you expect any new investment in the region?

[Dana Coffield:]

I'll start by answering your questions going backwards. So the acquisition dollars in the budget were for the bid round in Brazil that's already been finished, already behind us. There is another bid round pending, and we are evaluating whether or not to participate in that or not. So we've not yet made that decision. So the acquisition costs you saw on the revised budget was primarily from the bid round that's finished, behind us, in April. In terms of Ramiriqui production, I think gross production is right around...

[James Rozon:]

1,300.

[Dana Coffield:]

1,500 -- 1,300 barrels a day gross. That's probably 700 barrels -- 700, 800 barrels a day net to Gran Tierra. And now I'll turn it over to James to answer your question on G&A and tax, I believe.

[James Rozon:]

Yes, so in the quarter, we did record a withholding tax amount associated with the payments made between 2 of our subsidiaries. It's considered not a regular or recurring payment that will be made. So in this case, you would not expect to see that type of dollar figure or change or increase in our G&A going forward. We do record withholding taxes on payments that are made between our subsidiaries, but they are not made on a regular basis, and this was a larger-than-expected payment.

[Operator:]

Our next question comes from the line of Justin Anderson with Salman Partners.

[Justin Anderson:]

Guys, my question is relating to your robust production this quarter despite the significant OTA disruptions that we saw. And I wanted you to comment on, there seems to be a trade-off between maintaining robust production over the Costayaco and receiving higher net backs from OTA-delivered crude. And I was hoping that you guys could comment on your strategy or your view on that trade-off and whether there's any appetite with management to allow for more volatile quarterly production to maximize net backs?

[Dana Coffield:]

I think the answer is no. No to accepting more volatility. I think the market we're living in is volatile enough. So our plan is -- because these events are not predictable, our plan is to manage it, to be as stable and consistent as possible, to optimize the management of our reservoirs, our fields, manage our storage availability under our events. And then manage investor expectations and cash flow for operations. So just giving in to volatility and not being able to manage our business is not the right way to go in our view.

[Shane P. O’Leary:]

Yes, and I will just add to that, that when the OTA is down, we have been able, at times, to move significant volumes through Ecuador, and the difference in costs between the OTA and the Ecuador option is only about $1 a barrel. So we moved as much as 15,000 barrels a day through Ecuador at times. So it's not just the trade-off between the high cost of trucking and the OTA. There's also that option which is relatively low cost as a mitigation option.

[Operator:]

[Operator Instructions] Our next question comes from the line of David Beddis with GMP Securities.

[David Beddis:]

Sorry if I missed it, but what are the final steps that need to be taken to book reserves in Peru with the update coming in January?

[Dana Coffield:]

What we need is -- well, the prices we've gone through, what we need is the cost for the development of the field. We need our new map, our new 2D seismic map, that will give us new rock volume, oil in place number and then we run economics. So that's being done as we speak. Then we need the board approval to proceed to the next stage of the development, to commit to developing the field. That's the key trigger that we need to book reserves. With that approval, we can go to GLJ, and they will give us reserves. So we need to present the board with the development plan -- economic development plan. The board approves it, then we go to GLJ, and they will give us reserves assuming the board approves the development.

[David Beddis:]

And just because it's a day in time, this all has to happen by December 31. So we're pretty confident at this stage that all these wheels can get turning by that time?

[Dana Coffield:]

It doesn't need -- not all the needs to be done by December 31. The seismic program needs to be shot by December 31. The board letter can follow. So basically, the technical data has to be acquired before year end. And in fact, the technical data has been acquired before year end. So really, we just need to do our internal studies and then get the board approval which can come after year end. We're expecting the numbers to come out in January.

[David Beddis:]

Okay. That's great. And I guess on that same sort of a board meeting wavelength, when do you guys expect to come out with your 2014 budget and potential production outlook?

[Dana Coffield:]

In December. We're working on the budget right now. And we have a board meeting scheduled in December to approve that 2014 budget.

[Operator:]

Our next question comes from the line of Garett Ursu with Cormark Securities.

[Garett Ursu:]

Can you just clarify what the $54 million payment on termination of farm-in? What taxes you accrued in the quarter in all of those $54 million before tax, but can you just clarify deferred and potentially current taxes accrued?

[James Rozon:]

So the taxes that are accrued on the quarter are current taxes of $10.4 million.

[Operator:]

Our next question comes from the line of Marcus Sequeira with Deutsche Bank.

[Marcus Sequeira:]

Just a quick question, Argentina. I saw that you guys had a lot of work done during this quarter, and I think that the outlook is that it might continue into fourth quarter. I just wonder if you guys could confirm that? And also that by next year, the amount of workover should be much lower?

[Dana Coffield:]

Oh, the workover, yes. We are doing workovers this year, and we will continue doing workovers next year in Argentina, as well as our other precinct fields. It's normal course of business maintaining the wells. We did drop some of the workovers this year in preparation -- we allocated budget to drill horizontal well in Loma Montosa. We don't have a fixed number yet on workovers in Argentina next year. But I expect it will be some.

[Marcus Sequeira:]

Yes, but just in case of net backs, do you expect, obviously, net backs to return to positive territory, right, next year or maybe in this fourth quarter?

[Shane P. O’Leary:]

Our net backs are still positive in Argentina.

[Dana Coffield:]

And oil prices are rising in Argentina.

[Shane P. O’Leary:]

Yes, slightly, yes. So we're still making money in Argentina. The nature of our fields is they're quite mature. We have a number of pump failures, zones that water out, they have to be re-completed. Things like that. And I would say that workovers are an ongoing part of our business in Argentina.

[Operator:]

Our next question comes from the line of Pedro Medeiros with Citigroup.

[Pedro Medeiros:]

I actually have 2 other questions about the company strategy. First, I just wanted to understand from you if this failure attempt to farm out Brazil. Is farming out Brazil still on the plans for the next 12 months? And is it possible for you to review what was the bid price for that particular transaction? And secondly, strategically, since you are not increasing investment in Argentina, and as far as your net back goes, you're probably generating excess cash flow to your next year, what exactly is your plan for Argentina? Would you perhaps look for a farm-out there as well?

[Dana Coffield:]

With regards to Argentina, the plan is to continue reinvesting our cash flow in Argentina. There's a couple of exploration projects as well as in Brazil, in Peru, in Colombia, where, typically, the corporate strategy is to bring in partners on higher risk ventures. So we have a variety of projects throughout the company where we would contemplate taking on partners to help offset our capital exposure -- risk capital exposure.

[Pedro Medeiros:]

Okay. And is it possible to review the bid price for Brazil?

[Dana Coffield:]

No.

[Operator:]

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

[David Popowich:]

I'm sure this will probably be addressed when you come out with 2014 guidance. But I was just wondering how -- or sorry, what our expectations should be for production growth out of Moqueta next year? I'm just wondering if any potential delays in the permitting process would have potential to impact your 2014 guidance. And then just kind of on a related note, what are your expectations for Costayaco next year? And how much might it cost to keep production flat there?

[Dana Coffield:]

The -- for Moqueta, we're confident production is going to grow next year. The challenge there is not so much the global environmental permit, although it's a big piece of it. The key to growing production is water injection, increasing reservoir pressure. Our wells currently that have already been drilled are choked back because of lack of pressure support. So the well we're drilling now, Moqueta-12, will be a -- ultimately the sidetrack will be a water injector, and our plans are to increase that pressures through next year. So we're confident to get environmental permit early next year. If it slips a few weeks or months, it's still going to get done early next year and sort of confident Moqueta will grow fairly. David, what's your other question was?

[Shane P. O’Leary:]

On Costayaco. Costayaco continues to perform very, very well. And when that's happened in the past, we've had technical revisions upward in our reserves. It would be interesting to see what happens at year end here. But certainly, Costayaco has continued to outdeliver all of our expectations. So hopefully, we'll see some change there. I don't know. I don’t know if there's anything else I could say about it. I mean, we're supposed to have already been in decline, but that's not happening, and the waterflood continues to perform very well. Peer pressure in the reservoir continues to build, and we're just seeing outstanding results today.

[David Popowich:]

Yes, I guess I'm just wondering if there's a -- if there are signs that Costayaco does start to decline towards the middle of next year. Is that something that you can throw capital at an attempt to stabilize it? Or are you guys at the point where you just have to kind of start to let it blow down?

[Shane P. O’Leary:]

There might be some things we can do in shutting off water and things like that. And producing -- we've got multiple zones there, so we can shut off one zone and produce from another. That -- those types of things will help. Longer term, we have a polymer flood EOR project we're going to pilot, that could add reserves. That's early days. But more importantly, I think from a Colombia perspective, we expect to see the declines at Costayaco more than offset from Moqueta. So from a country perspective, you're not likely to see declines in Colombia.

[Operator:]

With no further questions in the queue. I would now like to turn the call back over to Mr. Dana Coffield with closing remarks. Please proceed.

[Dana Coffield:]

Thank you. I just, once again, would like to thank everyone for joining us today. And we look forward to speaking with you next quarter to update you on our progress. Thank you.