Gran Tierra Energy Inc.
Q2 2020 Earnings Call Transcript

Published: 5 Aug 2020

[Operator:]

Good morning, ladies and gentlemen, and welcome to Gran Tierra's Energy's Results Conference Call for the Second Quarter 2020. My name is Carmen, and I'll be your coordinator for today. At this time, all participants are in a listen-only mode. Following their initial remarks, we will conduct a question-and-answer session for securities analyst and institutions. Instructions will be provided at that time for you to queue all for questions. [Operator Instructions] I would like to remind everyone that this conference call is being webcast and recorded today, Wednesday, August 5, 2020, at 11

[Gary Guidry:]

Thank you, Carmen. Good morning and welcome to Gran Tierra's second quarter 2020 results conference call. My name is Gary Guidry, President and Chief Executive Officer. And with me today are Ryan Ellson, our Executive Vice President and Chief Financial Officer; and Tony Berthelet, our Chief Operating Officer. We issued a press release yesterday that included detailed information about our second quarter 2020 results, which is available on our website. On our first conference call -- first quarter call, we outlined several measures we have taken in response to the unprecedented volatility facing our industry including our decisive action to swiftly shut-in uneconomic production, deferred capital expenditures and implement cost-saving initiatives. The team has made significant progress on lowering, operating and G&A costs and done a great job managing the crisis on all fronts. We also continued to enhance and monitor our COVID-19 safety measures and ensure health and protection of our communities and employees and stakeholders. As we move forward, we remain agile in executing our strategy and our plan. We believe Gran Tierra is well-positioned to thrive in 2021 and above. I'll now turn the call over to Ryan Ellson.

[Ryan Ellson:]

Good morning, everyone. Our oil production in the second quarter was 2,165 barrels per day, down 32% in the first quarter of 2020. During Q2, volumes were impacted by deferred development drilling, shut-in of higher cost production wells and wells that were offline were waiting routine mechanical workovers and suspended production of Suroriente in PUD 7 blocks in the Southern Putumayo region due to force majeure lead to the local farmer’s blockade. Current production is approximately 19,000 BOE per day. Since March 2020, in response to the global economic downturn and lower combined prices, Gran Tierra rapidly implemented cost saving initiatives. Significant progress has been made on lowering costs through the renegotiation of vendor contracts and optimization of personnel and rental equipment. As a result Gran Tierra has reduced operating costs and cash G&A costs by 43% and 30% respectively since the first quarter. The majority of these cost structure are structural reductions and are expected to be maintained even if oil prices recover further. Furthermore, as a result of ongoing cost saving initiatives, we also expect per well drilling and completion capital cost reduced by 30% at Acordionero and 18% at Costayaco compared to 2019. During the quarter, Gran Tierra also successfully completed the semiannual redetermination of the company's credit facility. The borrowing base limit was redetermined to $225 million from the prior limit of $300 million. We're also granted relief under certain financial covenants until October 1, 2021. On the VAT front, Gran Tierra collected a total of $25 million in VAT and income tax receivable from the Colombian government during the second quarter. In July, the company received another $21 million and the further $30 million to $40 million is expected to be collected before the end of the year, resulting in a forecasted total of $76 million to $86 million to be collected in 2020. For the quarter, our net loss was $371 million compared with a net loss of $252 million in the prior quarter, primarily due to a noncash impairment of $398 million on the company's oil and gas properties as a result of significant lower oil prices. Adjusted EBITDA was $18 million with funds from operations being $6 million. With this year's oil price volatility in logistical challenge of COVID-19 Gran Tierra elected to significantly reduce the quarter's activity levels, preserve liquidity, and balance sheet strength. Q2 CapEx was only $5 million, a decrease of 89% compared to the prior quarter. Operating expenses of $9.62 per BOE were down 21% from the prior quarter, due to lower power generation costs reduction in rental equipment and cost savings attributed to lower activities. Workover expenses were $0.71 per BOE down 85% from the prior quarter, due to lower activity. Transportation expenses were $1.68 per BOE, up from $1.52 per BOE in the prior quarter due to higher pipeline sales. During the quarter, we entered into additional 2020 oil price hedges to provide further downside production against near-term low-price environment by securing three-way Brent collar, or a total of 11000 BOEs per day is now hedged for the second half of 2020. In summary, we have taken aggressive actions to protect our balance sheet and cash flows given the recent volatility faced in the industry. We have achieved significant reductions in operating G&A costs and we're well positioned to thrive in 2021 and beyond. I'll now turn the call over to Tony, our Chief Operating Officer to discuss our operational highlights.

[Tony Berthelet:]

Thanks, Ryan, and good morning everyone. With the recent recovery in oil prices and tightening of differentials we have initiated the required activities to safely resume several operations throughout our Colombian portfolio in strict accordance with COVID-19 protocols. I do want to note that, the evolving situation with the COVID-19 pandemic may impact the timing of the planned activities and the resulting volumes and scheduling of incremental production additions. At Acordionero plans call for the first workover rig to begin operations during the third quarter of 2020 and a second workover rig to start up in the fourth quarter of 2020. A total of 8 to 10 off-line wells are expected to be worked over to restore production by 2020 year end. Operations are conducted in sequential order as the rig moves from one well to the next. The total combined productive capacity of the 10 highest priority wells for workovers is estimated to be approximately 3,500 barrels of oil per day. On the development drilling front, one drilling rig is expected to restart operations during the fourth quarter of 2020 to drill one to two new oil wells by 2020 year end. These new wells are expected to begin production through the course of the first quarter 2021. The drilling rig is forecast to continue drilling new development oil wells at Acordionero throughout 2021 with the next four planned wells scheduled to be drilled from the new Southwest pad. Each of these new wells is expected to have an initial oil productive capacity of approximately 550 barrels of oil per day initial 30-day average rate. That's in line with the performance of wells drilled in the field over the last year. Moving to the Putumayo. A workover rig is expected to start operations during fourth quarter 2020 to work over two to four wells at Costayaco/Vonu. At Suroriente the restart of this block is expected during the second half of 2020. The block's working interest productive capacity is estimated to be approximately 3,600 barrels of oil per day. Lastly, the restart of the majority of our minor fields is expected over the course of the second half 2020. These fields combined working interest productive capacity is estimated to be approximately 1,900 barrels of oil per day. In summary, the internal initiatives we undertook during the severe downturn of 2020 were focused on portfolio optimization, deferring short-cycle investments and pacing projects to allow the safe resumption of operations when oil prices recovered and strict COVID-19 safety protocols were in place. We are analyzing multiple scenarios focused on maximizing returns and free cash flow in 2021 and to optimize the ultimate recovery free cash flow and long-term value from all assets. We believe our robust asset base will resume average production in excess of 30,000 barrels of oil equivalent per day in 2021, based on current assumptions, including commodity prices remaining at current levels and that there is no further global economic shutdown from the COVID-19 pandemic next year. I'll now turn the call back to the operator and we'll be happy to answer any questions. Carmen, please go ahead.

[Operator:]

Thank you. And ladies and gentlemen, we will now conduct a question-and-answer session for securities analysts. [Operator Instructions] Our first question is from Al Stanton with RBC. Please go ahead.

[Al Stanton:]

Yes. Good morning, guys. Just three questions, if I may. I'll just rattle them off and then let you come back. You've given CapEx guidance for the second half and also you haven't given much indication on the cost of the wells. So, if you can give some guidance on the cost of the well that would be really helpful. And also the sort of cost of the workovers, so that we can see how, perhaps, OpEx might be higher in Q4 than it is in Q2 and Q3? And then, the final question was, you've given good disclosure on the tax rebates or tax receivables. I was just wondering about current liabilities, how much of a burden they could be on -- during the second half. Thank you.

[Tony Berthelet:]

Al, its Tony here. I'll take the first two and I'll let Ryan take the last one. So cost of wells in Acordionero for drilling new wells, we're estimating around $2.5 million drill complete equipment tie. As mentioned, that's a pretty significant reduction from 2019 and just showing continued improvement as we execute repeated programs in that field. In terms of the cost of workovers for the second half, we're projecting roughly $2 million in the third quarter and then $8 million in the fourth quarter. And all of these are obviously OpEx-related workovers. So per well kind of in that $800,000 to $1 million range, depending on the scope of work for each well.

[Ryan Ellson:]

Okay. And then, with respect to tax rebates. So the question was, how does that coincide with our current liabilities?

[Al Stanton:]

Well, yes, yes. I mean, you've given us clarity on the money that's coming back to you. I was just wondering for a bit of clarity on the money going the other way. I mean, is the current liability is a reasonable size?

[Ryan Ellson:]

Yes. The current liabilities, since, if you look what we had at June 30, that's been reduced by about $30 million since June 30 and with most of all vendors all caught up.

[Al Stanton:]

Right. Okay. And then, just a final question, if I may. The CapEx guidance of $25 million to $35 million. I mean, do you think that's a stretch, given that we're just starting August now, or do you think that's still a good number?

[Ryan Ellson:]

We think that's a reasonable number. I think, the reality is, it is still complex with COVID-19 protocols and timing. But I think that's a fair range.

[Al Stanton:]

Thank you, guys.

[Ryan Ellson:]

Thanks, Al.

[Operator:]

Thank you. Our next question comes from Werner Riding with Peel Hunt.

[Werner Riding:]

Good morning, guys. I was wondering from a reserves perspective, if you could quantify the impact your asset impairments will have on your 2P reserves position?

[Ryan Ellson:]

Yes. I think, just on the asset impairment is the big driver with the impairment and you'll see some of our peers who report under IFRS took write-downs in Q1. Because we're a U.S. GAAP, we only use 1P reserves and it's the trailing 12 months. And so, it's really just a calculation for the price since the first day of the trailing 12 months. And so, there typically is a disconnect between the reserve valuators and our value especially -- and that's driven by both the volumes as well as the price, especially when you have a large spread between your 1P and your 2P reserves. And like I said unfortunately we can just use our 1P reserves.

[Werner Riding:]

Okay. So, you don't expect to see significant reduction in 2P reserves this year?

[Ryan Ellson:]

No.

[Werner Riding:]

Okay, great. Thanks.

[Ryan Ellson:]

Thanks.

[Operator:]

[Indiscernible] with MetLife. Please go ahead.

[Unidentified Analyst:]

Good morning. Thank you for taking my question. I would like some help from you guys to walk us through the cash flow numbers. So, we have some figures like the EBITDA of $18 million that proceeds from the hedges that was $17 million in the first half. Then we have the tax refund $25 million and the interest CapEx. I don't think that we already know, but it's still hard to figure out how to go from the EBITDA generation to the free cash flow -- the finance cash flow from operation as CapEx that is about $2 million. And then match that with a decline in cash that was about $22 million without a significant movement in that. So, if you could help us bridge these differences it would be great.

[Ryan Ellson:]

Yes, just walking through the -- from the EBIT -- the adjusted EBITDA to the -- our fund flow reported number the biggest difference is really just the adjusted EBITDA less the interest for the quarter. And that essentially gets us to the funds flow number that we quoted. And then on the second point, change of working capital, yes, the biggest change was cash did go down, but then two drivers is our accounts receivable went up quite a bit and that's essentially a use of cash. If you look at the end of March we're around $7 million and we were at about a $15 million change. And that's just because oil prices were a lot higher at June. That money was received in July. And then also there's a fairly significant reduction in our payable balance.

[Unidentified Analyst:]

Okay. I see. And also second question on this is in your guidance you said that you will have funds from operations of $25 million to $35 million and CapEx of also $25 million to $35 million. I would like also to match that with the expectations of the cash position until year end.

[Ryan Ellson:]

Yes, we don't forecast cash position in our guidance. And our guidance look just add on my last comment is the guidance is fluid just based on the ground realities of COVID-19. We need to make sure that we keep our employees and the communities that we operate safe and we're doing that. And so we need to be -- it's a staggered program it's a cautious program. And the last thing we want to have is as I put our contractors employees and communities at risk.

[Unidentified Analyst:]

Okay. But is it fair to say that as long as the funds flow operations as you define it, let's say capital expenditures is going to be a neutral free cash flow and we can expect a roughly stable cash position until year end, or are there any [Indiscernible] maybe tax refunds are not included there?

[Ryan Ellson:]

Yes, tax refunds are not included in there. So, that would be additive to the cash position. And then, obviously, whatever other changes we have in our working capital they are and whatnot. But that -- all else being equal, if everything else stays the same, that would be additive to our cash position.

[Unidentified Analyst:]

Okay, perfect. Thank you very much.

[Ryan Ellson:]

Thank you.

[Operator:]

Thank you. Our next question is from Alejandro Demichelis with Nau.

[Alejandro Demichelis:]

Yes, good morning gentlemen. Just to follow-up on previous question on the cash flow. Because I think Tony in his remarks was saying that you are basically planning for free cash flow at the fuel level. But then when we go to the corporate level, basically, you seem to be willing to spend every dollar that comes from cash flow from operations into CapEx. So, trying to understand how this work particularly with all the uncertainties that you have been describing.

[Ryan Ellson:]

Yes. And so really the guidance that we have is we have a range of capital between $25 million and $35 million and a range of funds flow from $25 million to $35 million. So, that's not the fuel level, that's at the corporate level. That's after interest, that's after G&A, et cetera.

[Alejandro Demichelis:]

Yes, that's fine. Just trying to understand the rationale for basically spending every dollar from the cash flow from operations when you're talking about all of these uncertainties on the ground at the macro level and so on and you also have the debt situation.

[Ryan Ellson:]

Yes. And the uncertainties there's a number of off ramps that we have. It's not we're committing to this entire program. Depending on what happens with oil price, depending on what happens with COVID-19. There are a number of off ramps.

[Alejandro Demichelis:]

Okay. That’s great. Thank you.

[Ryan Ellson:]

And the other thing too the reason why we are doing this is if you look at strip price for next year this is the way that we maximize free cash flow over an 18-month period.

[Alejandro Demichelis:]

Okay. So basically, you're trying to take advantage of what you see at the strip price for next year to maximize your cash flow?

[Ryan Ellson:]

Correct. Correct. And so not just by quarter-by-quarter but over an 18-month period this maximizes free cash flow because it gives us a much higher starting production profile in Q1 of next year.

[Alejandro Demichelis:]

Okay. That’s fantastic. Thank you.

[Operator:]

Thank you. Our next question is from Miguel Ospina with Compass.

[Miguel Ospina:]

Hello. Good morning. So this is like a follow-up of the previous questions. Just wanted to understand what are the main assumptions behind the EBITDA of $45 million to $65 million in terms of OpEx royalties and average production that you're expecting for the second half. The real question is related to accounts payable. It continues to be high at $116 million. My question here is how do you start this account and in general working capital to evolve over the next quarters? And my next question is related to if you can comment on your current cash levels? Thank you.

[Ryan Ellson:]

Okay. On the first point all the guidance that we have is what's in the press release. And so -- and really the number one driver on there is Brent price. Like I said, what we've done is we've tried to be very transparent and lay out all the activities that we want to do and the biggest change in that is -- what we can be certain on is the timing of those activities. But just to give all of our stakeholders idea as far as the productive capacity of the assets that's laid out in the press release. And then on the working capital movements our AP balance has come down substantially from year-end. I think if you look at the end of 2019, we had approximately $195 million, now it's down to $116 million. We did receive the additional VAT refunds in July which was used to reduce payables. And then, we'll have the current cash balance once we put out our Q3 results. But I wouldn't expect a significant change.

[Miguel Ospina:]

Okay. Thanks.

[Operator:]

Thank you. Our next question is from Josef Schachter with Schachter Energy.

[Josef Schachter:]

Good morning, guys. One question for Ryan and one for Gary. Ryan, the GAAP as you talked about the impairment for the quarter of $399 million what are the rules in the states for reversing reverting those back like in Canada where we got $50 or $60 per barrel many Canadian companies talk about under 50(101) they would be able to have the reversal of those impairments. What are the rules for the states? And what price do you need $50, $55, $60 Brent to start seeing that impairment reversal?

[Ryan Ellson:]

Yes. It's a great question. Under U.S. GAAP there is no reversal. Once it's gone, it's gone.

[Josef Schachter:]

Okay. Okay. And then for Gary with the problem with the farmer is still ongoing and the production out is this more of a political thing where Colombia is not getting money from the states? And it's almost like it will drag out past the U.S. election. And if Biden gets in and the Obama policy of helping Colombia comes back in then that's when the money might show up in Colombia to vacate and support the farmers? Is this a U.S. political drag on, or is this something that Columbia can resolve internally?

[Gary Guidry:]

Yes. I think it's really related to the coca growers and the eradication program, which has been ongoing even through the pandemic. What's caused the slowdown is the ability to have discussions, open discussions across the table from the farmers, because there are programs. There are programs in place to help the farmers move to a different crop a substitution program. The issue has been being able to sit down and talk. And we participate in that. We help support the government with the programs. And so I don't think that it's really, Josef, related to the U.S. election. I think it's more being able to have face-to-face discussions and they are ongoing. They've been reinitiated. And so as Tony said, we're in a position that we're getting ready to start the reactivation in the Southern Putumayo where most of this has occurred. And so we're confident that it will be something that can be managed regardless of what happens in the U.S. election.

[Josef Schachter:]

Okay. So you're saying that the U.S. funding to Columbia is still in place, and so that they have the funds to work out something with the farmers?

[Gary Guidry:]

Yes. And that's just one source of funding. There are numerous sources of funding.

[Josef Schachter:]

Okay. Super. Thanks very much guys.

[Gary Guidry:]

Thanks.

[Operator:]

Thank you. Our next question comes from Jamie Nicholson from Credit Suisse.

[Jamie Nicholson:]

Hi. Thanks for the call and thanks for taking my question. I just have a question on your covenants and your renegotiated bank agreements. Can you provide a little bit more detail on what those covenants will be in 2021 and what your current leverage to EBITDAX ratio is now as of second quarter 2020? And if there's any step-downs in that required for -- into 2021? Thanks.

[Ryan Ellson:]

Yes. The main thing and we have a lot of detail in our debt note and really the main thing is the total debt-to-EBITDA was -- previously it was four times and that's been -- we've received covenant relief until October 1. So really we wouldn't have to do the calculation until the end of the year. So it would be the end of 2021 is when we would need to be in compliant with that. If we do have a more constructive oil price environment and we're comfortable that we would exceed the covenant we can actually get out of the covenant early period.

[Jamie Nicholson:]

Okay. So you -- now you -- it looks like your debt-to-EBITDA was a little over seven times as of the second quarter. Is that correct?

[Ryan Ellson:]

No. Our trailing 12 months adjusted EBITDA we're about four times.

[Jamie Nicholson:]

Trailing 12 months, okay. And then…

[Ryan Ellson:]

Trailing -- everything is on a trailing basis.

[Jamie Nicholson:]

Okay. And so you're expecting that to spike up as -- like I guess what I calculated was your forecasted EBITDA for 2020 based on your EBITDA guidance is around seven times or a little more than that. Is that correct?

[Ryan Ellson:]

Yes. Yes because really we have some of the higher EBITDA quarters falling off from -- this would have been the trailing 12 months is we have the higher EBITDA quarters falling off from 2019 and replace with the lower price environment in 2020.

[Jamie Nicholson:]

And then you don't have any covenants -- leverage covenants until the end of 2021. Is that correct?

[Ryan Ellson:]

Correct. And it mainly comes with credit facility.

[Jamie Nicholson:]

Okay. Thanks.

[Ryan Ellson:]

And so based on our current forecast, we'll be on side with that by the end of next year.

[Jamie Nicholson:]

Okay. Thanks very much.

[Gary Guidry:]

Thank you.

[Operator:]

And thank you. This concludes our Q&A session. I would like to turn the call back to Gary Guidry for his final remarks.

[Gary Guidry:]

I'd like to once, again, thank everyone for joining us today. We look forward to speaking with you over the next quarter and update you on our ongoing progress. Thank you very much.

[Operator:]

Thank you, ladies and gentlemen for participating in today's program. You may now disconnect. Have a good day.