Gran Tierra Energy Inc. (GTE) Q1 2020 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to Gran Tierra's Energy's results conference call for the first quarter 2020. My name is Chris, 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, Tuesday, May 12, 2020, at 11:00 a.m. Eastern Standard 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 regards to this information and reconciliations of any non-GAAP measures discussed on today's call. Per barrel of oil equivalent, or BOE, amounts are based on a working interest sale 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 call -- 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 First 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 first quarter 2020 results, which is available on our website. We appreciate you calling in today for the first quarter update and hope you're healthy and well. We're living in unprecedented times for both the industry and our daily lives. The last few months have clearly been challenging for the industry, but I'm confident we will come out of this even stronger. We've built a business that has flexibility. Since we operate 95% of our asset base, we are able to be dynamic in how we respond to the volatile oil price environment. We've taken immediate actions to position ourselves through this downturn and are laser-focused on the things that we can control. We have significantly cut our 2020 capital program and are actively managing our production by shutting in higher cost barrels. We are confident we can quickly return these shut-in wells to production without reservoir damage or lasting impacts. We are also guarding our balance sheet with our hedges and continue to drive our operating and G&A cost reductions. We are very focused on preserving long-term value. We believe we have a competitive advantage to withstand the current challenging environment with our low base decline, conventional oil assets and our ability to control capital allocation and timing. I will now turn the call over to Ryan, and he'll discuss some of our financial highlights. Ryan?

Good morning, everyone. Our oil production in the first quarter was 29,527 barrels per day, down 10% from the fourth quarter of 2019. During Q1, volumes were impacted by suspended production at Suroriente in PUD 7 blocks in the Southern Putumayo region due to a local farmers' blockade, deferred development drilling, shut-in of higher cost production and wells that were off-line awaiting routine mechanical workovers. These wells are expected to remain off-line during this low-price environment. During the quarter, Gran Tierra quickly shifted its focus from production growth and free cash flow generation to protecting the balance sheet and preserving long-term value in response to the significant decline in world oil prices. This shift in focus was accomplished through adjusted oil production volumes, deferring capital investments and further optimization and lowering of operating and G&A costs. Significant progress has been made on lowering operating costs through the renegotiation of vendor contracts with material discounts achieved to date. Furthermore, additional operating cost initiatives include personnel and rental equipment optimization. In addition to reducing operating costs, we are benefiting from the recent depreciation of the Canadian dollar and Colombian peso. The Colombian peso has declined 18% versus U.S. dollar from the company's original budget estimate. The majority of Gran Tierra's operating costs is approximately 80% and G&A costs within Columbia are denominated in Colombian pesos. All G&A costs in Canada are denominated in Canadian dollars. Gran Tierra's executive team and Board of Directors have taken a 20% reduction in salary and retainer fees, respectively. In addition, a number of cost optimization and efficiency measures are being implemented that will further reduce the company's G&A costs to levels consistent with lower anticipated activity levels. We expect these changes to result in a reduction of 30% to 35% in G&A costs compared to the company's original budget. For the quarter, our net loss was $252 million compared with a net income of $27 million in the prior quarter. Due to the lower revenues primarily from the collapse in oil prices, unrealized loss on valuation of investments, goodwill impairment relating to acquisitions in 2006 and 2008 and the derecognition of a deferred tax asset. Adjusted EBITDA was $35 million and funds flow from operations were $22 million. During the quarter, we entered into additional 2020 oil price hedges to further downside protect against near-term low-price environment by securing costless Brent collars. The new hedges complement Gran Tierra's prior Brent oil hedges in place, which covers 6,000 barrels of production in the first half of 2020, and we currently have approximately 50% of our production hedged. Capital expenditures totaled $44.3 million, a decrease of 36% compared to Q4 2019 spend. Given the low-oil price environment, the remainder of the company's 2020 capital program is deferred, and only minimal maintenance expenditures planned for the rest of 2020. I'd also like to quickly touch on one of the new regulations issued by the Colombian government designed to support the oil industry during this downturn. Decree 535 was issued by the Ministry of Finance in order to expedite the recovery of value-added tax and income tax receivables from the tax authorities to ensure that such funds are received by companies in the short term. We expect to receive approximately $75 million in 2020. Although we are facing low oil prices in volatile markets, we believe Gran Tierra has a competitive advantage to withstand the current challenging environment with our low decline, conventional asset base, our ability to control capital allocation and our low-cost structure. We have taken aggressive actions to protect our balance sheet and cash flows by swiftly reducing our 2020 capital program and have targeted structural cash cost reductions through organizational operational changes. We will continue to monitor the near and long-term client price environment and leverage our financial and operational flexibility to further adjust our plans should it have become necessary. Lastly, we are in the process of the redetermination of our borrowing base, and we expect this to be completed in May of this year. I'll now turn the call over to Tony, Chief Operating Officer, to discuss our operational highlights.

Thanks, Ryan, and good morning, everyone. As Ryan mentioned, following the COVID-19 outbreak and the resulting large decrease in oil demand and prices, Gran Tierra has looked to defer the majority of capital expenditures for the remainder of 2020 and to stack all drilling and workover rigs. We took swift action to shut-in uneconomic production in the temporarily suspended fields with 0 or negative netbacks at current oil prices. We have taken precautions to minimize restart costs across all of these assets. We remain focused on ongoing production and water flooding of our core assets, Acordionero, Costayaco and Moqueta, which represent 81% of Gran Tierra's working interest proved reserves as of December 31, 2019. At Acordionero, we drilled a total of 5 development wells during the quarter, all directed at optimizing our waterflood program to maximize ultimate recovery and long-term value. We continue to achieve drilling efficiencies with the Acordionero 59 well drilled, completed and placed on production in 15 days. We also drilled and completed Acordionero 57 for a total capital cost of only $1.8 million. Wells drilled at Acordionero have consistently been delivered at capital costs below $2 million per well this year. Additional contract negotiations with vendors are forecast to further reduce infill drilling cost by approximately 20% to 30% once drilling restarts with price recovery. At the end of the quarter, a total of 9 oil wells required workovers to restore production. We have elected to defer these workovers due to the current low oil price environment. If Brent prices would recover to a level above $30 per barrel, we will consider initiating these workovers. In the Suroriente block, the Cohembi field was producing at approximately 4,000 barrels of oil per day prior to the farmers blockades. The field was continuing to positively respond to increased water injection and pump optimizations. Prior to the blockades in late February 2020, activities were underway to expand the Cohembi water treatment, injection and processing facilities under a 2-phased expansion program. The combined phase expansion is expected to boost gross water injection capacity from 19,000 to 60,000 barrels of water per day. In summary, we've taken decisive action to protect our balance sheet and cash flows by swiftly reducing our 2020 capital program. We believe we have a competitive advantage to withstand the current challenging environment given our low base decline in conventional oil assets, the ability to control capital allocation and low-cost structure. I'll now turn the call back to the operator, and we'll be happy to answer any questions. Operator, please go ahead.

[Operator Instructions]. And our first question comes from the line of David Round with BMO Capital Markets.

Can I start with the workovers, please? I guess the reason the question really is, because I was expecting these to be trending down this quarter, and I see there's a reasonable cost in Q1. And obviously, you mentioned you've got another 9 wells down at the moment. So look, it seems quite high. I'm wondering, is there a consistent issue and have you seen any improvement. ESP and power trips were an issue before? So have you seen any improvement of securing a reliable power source? And maybe a follow-up. I think you've got about 5,000 barrels a day down at the moment. That was from a previous announcement. So correct me if I'm wrong there. But what are you thinking and forecasting in Q2 in terms of additional production downtime or production that you could lose to workovers? And actually maybe I'll just quickly add a Part C. Can you just remind us what workover costs? Because if we're talking about 5,000 barrels a day across 9 wells, you've probably got some wells doing about 1,000 barrels a day, which would surely pay back quite quickly even at these prices.

Yes. Great. Thanks, David. It's Tony here. So some of the workover activity in the first quarter, to be sure, were unbudgeted related to -- primarily due to sand issues associated with causing a failure in the artificial lift equipment. Two of those workovers, however, we did move forward because they were injector conversions that we wanted to get ahead just to be able to proactively manage voidage replacement. So that did come with some accelerated capital or costs associated with that work. In terms of power and how we're managing that, we ran the first 6 weeks of the year with a stable power generation. And then we had a series of outages that were -- two of them being linked and two being unrelated events. Since we've recovered from those and have improved our reliability of our power generation. We've been without a power failure since that time, which would have been the end of February. So again, the unfortunate part of that power outage has caused some additional wells to go down, which we -- as we've talked about, 9 wells at the end of the quarter that we'll be looking to repair. In terms of costs, yes, we would agree that there's some high-volume wells here, and it's really just about managing cash flow for the next quarter in terms of spending that money. Capital cost to remove and repair an ESP are in the $800,000 range, depending on sand cleanout activity, but ultimately, that's kind of a rough budget of what we're looking at. So yes, some of these will be quick payout, and we work pretty closely with finance to determine when we would initiate that activity again. In terms of what Q2 looks like, we have had a couple of additional failures in -- since the end of the quarter. But ultimately, as you mentioned, we're still in that 4,000 barrels of oil per day. 4,000 to 5,000 barrels of oil per day that are down currently awaiting workovers. So that should give you some indication based on a Q1 average of above 15,000 barrels of oil per day of where we're at.

And then David, just on the workovers, in the current price environment, we can make a return on some of that, but we're not in a huge hurry to get these barrels out of the ground in a $30 oil price environment. So part of that is just timing just to maximize returns in the future. And also, just -- there are restrictions within country, COVID-19 restrictions. It is -- it does make it more difficult to move even a workover rig around. And so in the next 4 to 6 weeks, we'll reassess those workovers.

And our next question comes from the line of James Hubbard with Numis.

Two questions, please. So your costs seem a lot more variable than maybe we would have expected a couple of months ago in that when you get into it, you can cut your workovers, the royalty, obviously, is directly variable, the discount, et cetera. And so I'm wondering where you think you can get your cash breakeven now in terms of cash netback, so the bottom line, because my -- I'm just playing around, and I may have this wrong, but it seems to me that if your workover is going to be de minimis, then you're fine at about $30 a barrel. I'm just wondering if that's more or less what you think or if you're thinking of a radically different number there. And then expanding on that on a second question, if we stay in the current oil price environment, $20 to $30, and so you stay in your current mode of conserving as much as possible, I'm wondering, is that more a decision of cash flows? Or is it, as you just alluded to in answering the last question, this oil could be worth a lot more in the future, we'll leave it in the ground and maximize value that way? I'm wondering what the main drivers is of your philosophy by now is?

Yes. Thanks, Jim. I'll take both those. The first one, yes, the $30 number is a reasonable number. We've been running -- our base case for this year is oil stays at $30 Brent for the remainder of the year. And so with that, with our VAT refunds, income tax refunds, et cetera, we're comfortable we can manage the balance sheet. And for the second question, you're spot on. We're just not in a huge hurry to get barrels out of the ground in this environment. Because once those barrels are gone there, as you know, they're going for good. And so we'd rather just keep them in the ground right now.

Our next question comes from the line of Alejandro Demichelis with NAU Securities.

A couple of questions, just to follow-up from James' question here. On your cash cost, if would you kind of run the numbers now and without kind of having the VAT refund, what do you think that the cash cost could be at this point in time? And then the second question is in your press release, you do mention the situation of the redetermination and also the potential breach in the covenant. So maybe you can give us some kind of indication how those discussions are going on the redetermination of the loan and also on any waiver on the covenants, please.

Okay. With respect to the cash costs, if you look at the combination, we've shut-in anything -- all of our higher cost fields -- relatively higher cost fields. So right now, we're just producing from our 3 core assets, which is about 80% of our 1P reserves. And that's Costyaco, Makena and Acordionero we think our operating costs going forward are going to be in the $8 range on a blended basis. And so that gives you an idea on the operating costs. Differentials have been moving around lots in Colombia. Obviously, we can't control that, and we can't control Brent price. But from the cash cost basis, we think we've done a good job of really driving those down. And a lot of those reductions are structural changes. On the second question on the redetermination, I think it's pretty clear the way we have it in the financial statements. Management is optimistic that we'll come up with a solution. And we'll have -- we'll know the outcome by the end of this month. But I would say conversations have been very positive and constructive.

And in terms of the headroom, the liquidity headroom that you have there, that use kind of credit lines, have those been confirmed?

No. No. It's all part of the redetermination process.

Our next question comes from the line of Josef Schachter with Schachter Energy.

And thank you for having the conference call and taking my questions. In terms of the upside, you've got the shutdown in Suroriente that is unknown in terms of when that would come back. You mentioned Acordionero, USD 30 per Brent to do the workovers. What prices would you need to start looking at raising production? Are you looking at $35, $40, $45? And then how much production increments could you see from different areas as those prices do recover if they recover in, let's say, late Q3, Q4 of this year?

Yes. Thanks, Josef. It's Ryan. Yes. I think on the -- oil has been very volatile, not just the headline Brent number and WGI for -- as well, but also differentials. So I think we would like to see some stability north of $30 before -- and really, the order would be Acordionero and then Suroriente. And so I think north of $30. So in that $30 to $40 range, we would look at the program for new drilling. Tony mentioned, the team has done a great job of getting cost down at Acordionero, we think they will be sub-$2 -- $2 million. So those are very economic. But again, we're not really going to accelerate those barrels out of the ground in this environment. So I think for -- to resume development drilling, it would be high $30s, low $40s.

Josef, just to add, part of Suroriente, the issues with the cocoa farmers is still underway. That's not been resolved, and that's a second issue that's really driving when that fuel comes online in addition to what Ryan said on economics.

Okay. And where is production right now, just to put that in context?

Yes. 21,000, 22,000 barrels a day.

And our last question comes from the line of Al Stanton with RBC.

Yes. Somebody's just stolen my thunder. I was actually going to ask what production was doing at the moment. Would you use 21% to 22% as a decent average for the second quarter?

Yes. I think that's a good number.

And you've all spoken about preserving long-term value, but some of my concerns are a little more immediate. So I'm just wondering, whilst it's good to leave some of the reserves in the ground for better days, you do need to generate some EBITDA. So I'm just wondering what are the pitfalls of falling foul of your covenants? Is it just with respect to the RBL? And what do the bondholders want? I mean as long as you keep paying the interest, is that enough? Or should I worry about the covenants for them as well?

Yes. As far as -- on the first question, as far as EBITDA, you're 100% right. But also, like I'd mentioned, too, even right now, if we wanted to move a service rig work over these wells, with the COVID-19 restrictions, it would be complicated to do. And so -- and we expect that to be 4 to 6 weeks out. And then like I said, if -- at current strip pricing, it's a little north of 35%, then we would look at doing those workovers. So we're exactly right. It definitely is finding that right balance. And then on the second point are -- on the RBL, we do have maintenance based covenants that if we're not compliant, it is an event to default, and that's why we're working with the lenders, as we disclosed, to get a waiver on those. And then on the bonds, they are incurrence-based covenants.

What does that mean in layman's terms, please?

No. We just get -- if we're in violation, we just can't take on additional debt.

And our next question comes from the line of Alexis Panton with Stiefel.

I have a question on liquidity, more of a sort of credit bondholder question here. You finished the quarter with about $40 million of cash. Your accounts receivable's down to less than $10 million. You -- it looks like you had an issue with your suppliers during the quarter. We had a big drop in accounts payable. And the way I calculate it, about 100-day decline in the average time that you pay accounts -- you pay your suppliers, which is sort of typical of this type of cycle when you have nervous suppliers. You have about, as far as I calculate, $96 million available still under the credit line. Obviously, that's subject to incurrence tests, but they're backward looking, which imply you have the ability to take them down. As of today, it seems unlikely you could do so after the second quarter. So in the context of all of this and the fact you have a coupon payment due, I think, in 11 days on the 2027 notes, where do you stand in terms of the puzzle here in terms of liquidity? Have you drawn down further on your credit facility and can you give us a bit more color, as I alluded to, with respect to accounts payable, which looks like a big loss of cash flow during the quarter? And I guess, finally, in relation to this, the $75 million you mentioned in VAT receipts expected for this year, can you give us a sense of timing on those? I think liquidity is obviously becoming something of a critical question.

Yes. With respect to the payables, we had a very active Q4 program, as you're aware. And so it really is just unwinding of those payables in the quarter. So I would say it's more normal course. I wouldn't say it's nervous suppliers, it's normal course payables that we paid. And with respect to liquidity, we had $204 million drawn on the RBL. We still have $204 million drawn on that. And that really is -- our next results will be at the end of this quarter.

Can you sort of give us a sense of your intentions with the upcoming coupon? Obviously, the bonds are trading at a price that suggests the market is expecting you not to make it?

We fully expect to make it.

And our next question comes from the line of Stephane Foucaud with Auctus Advisors.

I had a few operational questions. First, you talked about current production of 21,000, 22,000 barrels a day. Assuming that all prices don't change, assuming that the Suroriente situation does not change, is that a good number for Q3, Q4 on $30 a barrel? Then a question on tax. So you talked, I think, about the $75 million VAT that you expect to recover in 2020. Have you already recovered some of that? Or is it what remains to be recovered in Q3, Q4 -- Q3 -- Q2, 3Q, Q4. And lastly, you talked about minimum maintenance CapEx again in $30 environments, what would that be more or less?

Yes. I'll take the -- it's Tony here. I'll take the question on Q3, Q4 production. At a $30 price environment, as Ryan has already mentioned, until we understand better what's going to happen with COVID policy relaxation, that will drive what we do in terms of activity with the wells that are waiting on workover activity right now. So it's -- that's a difficult number to provide any kind of guidance on for this third and fourth quarter. With respect to -- sorry, what was the second part of that question?

As that was -- before going to the VAT, as that was around the minimum CapEx, again, assuming $30 barrel...

Yes. So the minimum capital expenditures that we plan to do for the rest of the year are a combination of some of the maintenance activity that we need to do just to maintain the facilities and infrastructure, but also preparing for licensing and of future projects. So there is some capital associated with that, that we'll continue to spend just so that we continue to maintain the flexibility to reactivate and get activity started again from a regulatory and government perspective.

So it's, what, sub 10, you would say?

Pardon me?

Sub $10 million? Just to have some sort of sense for the number.

No, no. It won't be that high. I think we'll probably be in that $2 million to $5 million for the rest of the year associated with those costs.

Yes. Okay. And lastly, was around the VAT, whether the $75 million you talked about. I think on the beginning of the call, you have already received some of that or that's still to come in Q2, Q3, Q4?

Yes. We expect to come Q2, Q3, Q4. We expect about $50 million over the next 5 months.

Right. And there is no cash tax, corporate tax to be made in the balance of the year, is it? Or would that be offset?

No. Correct. No cash, just taxes.

And gentlemen, I'm not showing any further questions on the phone line.

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

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.