Gran Tierra Energy Inc. (GTE) Q2 2019 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to Gran Tierra Energy's Results Conference Call for the Second Quarter 2019. My name is Mao, 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, Thursday, August 8, 2019, at 11 o'clock in the morning Eastern Time. Today's discussion may include certain forward-looking information as well as certain non-GAAP financial measures. Please refer to the earnings and operational update press release we issued yesterday for important disclaimers with regard to this information and reconciliation of any non-GAAP measures discussed on today's call. Per barrel of all equivalent or BOE amounts are based on a working interest sales before royalties. Finally, this earnings call is the property of Gran Tierra Energy Inc. Any copying or rebroadcasting of this call is expressly forbidden without the written consent of Gran Tierra Energy. I will now turn the conference call over to Gary Guidry, President and Chief Executive Officer of Gran Tierra. Mr. Guidry, please, go ahead.

Thank you, Operator. Good morning, and welcome to Gran Tierra's Second Quarter 2019 Results Conference Call. My name is Gary Guidry, President and Chief Executive Officer and with me today is Ryan Ellson, our Executive Vice President and Chief Financial Officer. We issued a press release yesterday that included detailed information about our second quarter 2019 results, which is available on our website. After a few brief comments, we will then open the line for questions. I'll now turn the call over to Ryan Ellson, our Executive Vice President, Chief Financial Officer, to discuss some of our operational and financial highlights. Ryan, go ahead.

Good morning, everyone. First, I'll mention some significant achievements subsequent to the end of Q2. Our team has successfully completed the commission of the expanded Acordionero's central processing and water injection facilities as well as the installation of the gas to power turbines. We've also significantly ramped up Acordionero's injection to approximately 28,500 barrels of water injected per day during the May to July 2019 time frame. And we expect to further increase Acordionero's injection to about 40,000 barrels per day during this month. With this plan, water injection increase will forecast in a positive impact on Acordionero's reservoir pressure, which will support increased oil production rates from both current and future producers and ultimate oil recovery efficiency. We are very excited about recent results from the Acordionero-48 well, which opens up a new Lisama E light oil development using the same infrastructure that we just expanded. For context, the Lisama E is located just below the main Lisama A and C reservoirs. And although this overpressured zone has been penetrated with other wells in the Acordionero field, the Acordionero-48 well is the first opportunity for us to test this new reservoir horizon. In terms of our Q2 results, our production averaged 35,340 barrels of oil per day, which is impacted by the blockade in the Southern Putumayo, which has been successfully resolved and the temporary reduction in production at Acordionero, as we ramped that field's water injection. Despite these temporary production issues, Gran Tierra achieved strong financial performance during the quarter. Our Q2 net income was $39 million. EBITDA increased 24% to $115 million in Q2 from Q1, our quarterly funds flow from operations also grew significantly to $88 million or $0.23 on a per share basis, an increase of 17% compared with $75 million in Q1. During the first half of 2019, we returned $24 million to stockholders through our buyback of 10.4 million shares or almost 3% of our outstanding shares at the start of 2019. Our balance sheet remains strong with our net debt-to-EBITDA at the end of Q2 standing at 1.4x on a trailing 12-month basis. On the basis of annualized Q2 EBITDA, this ratio is 1.2x. Oil and gas sales increased to $158 million during the quarter. We continue to have top quartile operating netbacks with our Q2 operating netback increasing 10% compared with Q1 to $33 per barrel. I'd like to touch on our updated 2019 guidance. We're now forecasting production to ramp up during the remainder of 2019, and we revised our full year 2019 production forecast to 36,500 to 37,500 barrels of oil per day. We have updated our 2019 total capital guidance to a range $330 million to $340 million and our 2019 cash flow guidance to a range of $333 million to $355 million. I'd like to highlight 2 new blocks that we won in the recent ANH bid rounds. LLA-85 in the Llanos Basin and VMM-24 in the Middle Mag. These blocks complement our current acreage position in both of these basins. We efficiently signed contracts for our 3 exploration blocks in Ecuador, which are contiguous to our Putumayo Basin assets on the Colombian side of the border. In terms of upcoming catalysts, during the second half of 2019, we have many potential catalysts, including the drilling of 13 to 15 development and exploration wells, with planned appraisal of the Lisama E Sand in Acordionero and the drilling of the Vonu Este well in the PUT-1 block in the Putumayo. We're just targeting the fractured A-Limestone and the U Sand. Overall, we believe, we have significant financial flexibility and operational momentum. With our facilities expansion now complete at Acordionero and the planned completion of our large 3D seismic program in the Putumayo during Q3, we forecast Gran Tierra will generate free cash flow in Q4 this year and in 2020. Looking at 2020, we plan to refocus on our sustainable free cash flow profile, wasn't planned to use for net debt reduction and share buybacks. We expect strong production and cash flow into 2020 and beyond, while maintaining active exploration program of 6 to 10 wells per year. While the temporary reduction in production during Q2 was unfortunate, our underlying asset value was not changed and Gran Tierra is in an excellent position with a strong free cash flow profile, visible production growth, strong balance sheet and a world-class exploration portfolio comprised of 34 blocks across 4 proven and prolific basins in Columbia and Ecuador with excess infrastructure. I'll now turn the call back to the operator and we'll be happy to take questions. Operator, please go ahead.

[Operator Instructions]. First question comes from the line of Ian Macqueen of Eight.

Just a quick question on Acordionero. Can you tell us what the production is currently? And how you see the production evolving as you continue to drill development wells and start to see a waterflood response?

Yes. Ian, what was the second part of that question?

How do you see the production evolving as you start to see a waterflood response and continue with the development drill?

Okay. Yes. Current production is about 16,000 barrels per day from Acordionero. We're injecting right at 30,000 barrels of water a day. We've tested our facility at 40,000. And we have the capacity to go beyond that. So the real -- we're very confident that we will be back with the four-handle on our production. It's a matter of timing and you get on it, it's the response. We're already starting to see response. We did see response with our pilot program. But we're in the process of ramping our water injection up and will be there in August, we'll be at the 40,000 barrel a day. So I would say, over the coming months, we will see response in earnest. We're -- our main objective is voidage replacement where we've achieved that already in the 70%, 80% of our reserves, and we're approaching that right now with our ramping of injections. So the short answer to your question is, over the next few months.

Okay. And then I think the production at a higher peak was about 21,000 barrels a day. Is that a reasonable expectation to think that it would go back to? Or where should it peak again?

It's reasonable. We were at 21,000 to 23,000 barrels per day. We're very confident that we will be back there. We now have the facilities all within our control for both the injection and handling water cuts as they increase. And so I think it's very reasonable. We can handle up to 30,000 barrels of oil per day and about a bit over 40,000 barrels of fluid per day through our facilities. So we're quite confident we'll be able to handle those volumes.

Your next question comes from the line of David Round of BMO Capital Markets.

I might have missed it, so apologies if I did. But just on the differentials, can you talk a bit more about the differentials you've seen in the quarter? If you can elaborate how much in particular? How much of your crude is sold at Vasconia? And was there much of a change in the quarter between where you sold your crude? And the second question is, you said the field is responding positively to increased water injection, can you just elaborate exactly what you're seeing there? And what your expectations are for the next year?

Yes, it's Ryan. With respect to differentials, both the -- all of our barrels are priced off of Brent minus either Vasconia or Gaztea. Both of those differentials have been quite tight this year just with the shortage of heavies worldwide. So we've obviously benefited by that by a couple of dollars. We also have -- in May, we -- for a Acordionero barrels, in particular, we entered into new market arrangements, which increased our netback and really narrowed the differential by $0.75 to $1.

In terms of Cohembi, what we're seeing is very visible, very rapidly, is pressure responses in the wells, we're seeing increased fluid levels. The production increases are on the order of 500, 600 barrels a day. But what really is exciting for us is expanding the water injection capability followed by water sourcing. And that's what we're doing this year as we -- our objective is to have all of our water sourced from produced water, non-potable produced water. At the same time, in parallel, we're expanding our facilities. And our objective towards the end of this year is to get up to the 50,000, 60,000 barrels a day of injection capacity. We have that capacity to handle the production with the infrastructure that we have in place. And so the answer to your question is, the reason we're quite confident is we're seeing pressure response and wells surrounding the injectors that we have in place.

Yes, and, David, as Gary mentioned, we -- production increased 500, 600. That's net. So the actual fuel production increased by over 1,000 barrels per day without drilling a well.

Next question comes from the line of [indiscernible].

Can you comment on how your strategy would change, both operationally and from a capital allocation perspective if the oil were to drop to $40 a barrel for an extended period of time?

We have about 10,000 barrels a day hedged at the moment. And our objective was to protect our capital program, our long-term capital program, down to about $50 a barrel. Below $50, it's a bit extreme and, let's say, if it does hit $40, we operate effectively all of our assets, all of our exploration. And so our ability to slow down or speed up our capital program is within our control. The one thing that is important to us is the regulatory, the permitting process for exploration. We have a fantastic portfolio, but it takes time to get that permitting. And so our flexibility and control is probably the most important thing to us and we have that all within our means.

In addition, as far as capital allocation, in all of our core fields, all of the major facilities are in place. So we don't have any large major capital projects on the horizon. So again, that helps with our capital allocation.

And what about your dividend and share buyback policy? And would that change under different oil price scenarios?

Yes. Currently, we don't pay dividend. And our objective for next years is for a free cash flow, so really operating cash flow less our CapEx to allocate that to net debt reduction and share buybacks on a 50-50 basis. To the extent that we didn't have free cash flow, we would not be doing a share buyback.

But we have a program in place now.

But we do have a program in place right now, and we don't pay dividend.

Okay. And just one last question related to this. What is the breakeven cost of your fields on kind of a weighted average basis based on your production currently?

About $30.

Next question comes from the line of Nikolay Menteshashvili of Insight Investment.

Most of the questions have been answered. Just a couple left. Going forward, as you mentioned that you expect the free cash flow generation in 2020. Do you expect that -- what are the basic assumptions that you're using? Are you using $65 oil as well? And do you expect capital CapEx to remain broadly stable and then free cash flow to grow as production grows? Or what's basically the dynamics that -- because this year you'll be just about free cash flow positive, right?

Yes. With respect to the free cash flow profile, that -- at $65 Brent, that is about $100 million of free cash flow for next year. And the key for us is we don't plan quarter-by-quarter. We really do 5-year plans. And Gary alluded to it earlier that our main strategic objective is to make sure we control all blocks, operate all blocks, just to have that flexibility with capital allocation. And that gives us long flexibility over the 5-year period.

Okay. And let's say, you're exploiting the capital flexibility as well in case oil prices fall down further from the current levels?

Yes. Very correct. And this year, we have 10,000 barrels hedged with the floor of $60.

Okay. And then secondly, you announced the tender for the convertible, that was one of the reasons for issuing the bond early in the year. How is the tender going? And what's the take up this year so far?

Yes. We've closed that tender. We've repurchased all of the -- with the exception of the $115 million, we've repurchased all, but $3,000.

Next question comes from the line of Miguel Ospina of Compass Group.

I have two questions. The first one with the IMO 2020 regulation coming in next year, where would you see your Vasconia differential going? And the second one is where do you see your capital program next year? Does it make sense to assume CapEx, again, above $300 million?

Yes. With the first question with respect to IMO, it's hard to quantify that. We've been working with a lot of the marketing groups who monetize our oil for us. We expect, on the downside, sales revenue impact of $1 to $2 a barrel. And with respect to the -- and that's on the downside scenario. With respect to capital for next year, we will release our 2019 -- 2020 budget in December of this year, but we are targeting free cash flow next year of that $75 million to $100 million.

Next question comes from the line of Al Stanton of RBC.

A couple of questions from me as well, please. Just in -- with respect to Acordionero, and then you also mentioned your 5-year plan, how do you envisage production growing? I mean looking at the averages for this year in the second half, you might exit with a full handle, but you're not going to average $40-something. I don't suppose. So how would we look at 2020 production and subsequent production? Should it be seen as a -- perhaps a little longer plateau rather than the peak? And then if I may, just quick question on exploration. A couple of wells -- all of a sudden, some of the spending and the couple of wells have shifted to the right. I was wondering if that was just delays or whether there was some financial management associated with that?

Thanks, Al. The answer to your questions on Acordionero, we announced in our last operations release that we expect reserves to grow and that's because the field was extended to the South, as we shot BSPs, we correlated the seismic, we were confident enough to step out. A pretty good step as far as we could reach to the South. And it proves that we are correct that the structure has changed. And so we focused quite hard on our probable and our possible reserves now that we've defined the tank. We've defined both aerially and we -- what we've not defined is how much we might find below is that E -- the E Sand's discovery is we think quite exciting. We also have D Sand that we'll start exploiting. Now that we have facilities in place, we have the ability to start ramping our water injection program. And so we've built our production facilities to handle 30,000 barrels a day for a reason. We believe our possible reserves, we believe our probable reserves, and as a matter of how efficient we can be at asset management, it's flooding that field. And we have a very strong team now that they have the infrastructure to start applying it over the next couple of years. And so that hopefully answers that question. And in terms of exploration, the big one for us, we still are excited about the Ayombero discovery to the North. It's high-pressured. And we -- we're having -- because there's not equipment in the country, we finally concluded that we have to defer our work over a completion activity with the exception of the first well we drilled, it's producing a couple of hundred barrels a day with no decline. We have to really defer that until we can get a snuffing unit in country to work under pressure conditions. And the rest of our program really is, it's financial, it's more of logistics. Getting our logistics in place and permitting in place. And so we still believe that we can have an active 5 to 10 well exploration program per year for the next couple of years.

Yes. And we're quite excited about the Vonu Este well and that's the first time that we're able to appraise the Vonu discovery. If you recall the Vonu discovery was accumed over 750,000 barrels from the fractured A-Limestone. So this will be an appraise in that.

And one final question, if I may. Some of your peers have been talking about upcoming licensing round. So I mean, is your plate full? Or do you continue to accumulate acreage?

I think as you know, a constant process of upgrading your portfolio and what's been talked about by Ecopetrol that -- they're really the big acreage holder, big producer in the country. And the ANH have talked about maybe divesting some of the under -- or undeveloped fields in the country, and I think that will be a competitive process and we'll all be on an equal footing in competing for that. But having said that, we're completely happy with the portfolio we have, and nothing else hits the table. It's really an opportunity going forward. We have a great portfolio, and we look forward to drilling it over the next few years.

And we'll be continuing to be selective. [Indiscernible] ANH around, there was over 20 blocks offered and we only bid on two. So it's the acreage that we see the potential upside and it's close to our existing acreage and infrastructure, we will take a look at it.

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

Okay. Thank you, Operator. I would like to thank, everyone, again, for joining us today, and we look forward to speaking with all of you over the next quarter and update you on our ongoing progress. Thanks for joining us.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation, and have a wonderful day. You may all disconnect.