Gran Tierra Energy Inc. Q1 FY2020 Earnings Call

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. 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 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 the 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 Colombia 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. This is due to the lower revenues primarily from the collapse in oil prices, unrealized loss on the 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 provide further downside protection 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 are 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 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 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.

Can I start with the workovers, please? I guess the reason for 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. Obviously, you mentioned you've got another 9 wells down at the moment. 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 in 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 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 are? 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.

Thank you, David. It's Tony here. Some of the workover activities in the first quarter were unplanned, mainly due to sand issues that caused failures in the artificial lift equipment. However, we proceeded with two of those workovers because they involved injector conversions that we wanted to complete proactively for managing voidage replacement. This did lead to some increased capital costs. Regarding our power management, we had stable power generation for the first six weeks of the year, followed by a series of outages, two of which were linked and two unrelated. Since recovering from those outages and improving our power generation reliability, we have not experienced any power failures since the end of February. Unfortunately, the outages led to additional wells going offline, and we are looking at repairing nine wells by the end of the quarter. In terms of costs, although we acknowledge that there are some high-volume wells, we are primarily focused on managing cash flow for the next quarter. The capital cost for removing and repairing an ESP is around $800,000, depending on the sand cleanout needed, which provides a rough budget for us. Some of these repairs will have a quick payout, and we coordinate with finance to decide when to initiate those activities. Looking ahead to Q2, we have encountered a couple more failures since the end of the quarter. Currently, we are producing between 4,000 to 5,000 barrels of oil per day that are down and awaiting workovers, which indicates our current situation compared to a Q1 average of over 15,000 barrels of oil per day.

David, regarding the workovers, in the current pricing environment, we can achieve a return on some of that, but we are not in a rush to extract these barrels while oil is at $30 per barrel. This is partly about timing to maximize future returns. Additionally, there are restrictions in the country due to COVID-19, which complicates the movement of workover rigs. We plan to reassess the workovers in the next four to six weeks.

I have two questions. Your costs appear to be more variable than we expected a few months ago. It seems that when you dive into it, you can adjust your workovers, and the royalty is clearly variable alongside the discount. I'm curious about where you believe your cash breakeven point is in terms of cash netback. Based on my calculations, if your workover expenses are going to be minimal, it appears you would be fine at around $30 a barrel. Is that roughly in line with your thoughts, or do you have a different figure in mind? For my second question, if the current oil price remains in the $20 to $30 range and you continue to focus on conserving as much as possible, is that primarily a decision driven by cash flow, or is it more about the belief that this oil could significantly increase in value in the future, leading you to leave it in the ground? I'm interested in understanding the main drivers behind your current philosophy.

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, they are going for good. And so we'd rather just keep them in the ground right now.

A couple of questions, just to follow up from James' question here. On your cash cost, if you would 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 indication of 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 all of our higher cost fields, so right now, we're just producing from our 3 core assets, which is about 80% of our 1P reserves. 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. That gives you an idea on the operating costs. Differentials have been moving around a lot 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 regarding 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. 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.

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. The oil price has been quite volatile, not only for the headline Brent and WTI figures but also for differentials. We would like to see some stability above $30 before proceeding, starting with Acordionero and then Suroriente. If we see prices in the $30 to $40 range, we would consider a new drilling program. Tony mentioned that the team has successfully reduced costs at Acordionero, which we expect to be under $2 million, making it economically viable. However, we won't ramp up production in this current environment. To resume development drilling, we would need prices in the high $30s to low $40s.

Josef, just to add, part of Suroriente, the issues with the cocoa farmers are still underway. That's not been resolved, and that's a second issue that's really driving when that field comes online in addition to what Ryan said on economics. Yes. 21,000, 22,000 barrels a day.

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, while 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. Regarding the first question about EBITDA, you're absolutely correct. However, as I mentioned, even now, if we wanted to move service rig work over to these wells, it would be complicated due to COVID-19 restrictions. We anticipate that this will take 4 to 6 weeks. If Brent prices were to rise above $30 per barrel, we would consider doing those workovers. We are definitely focused on finding the right balance. As for the second point about the RBL, we have maintenance-based covenants, and if we do not comply, it could lead to an event of default. That's why we are working with the lenders to obtain a waiver on those. The bonds have incurrence-based covenants.

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

No, if we are in violation, we cannot take on additional debt.

I have a question about liquidity, which relates to the credit bondholders. You ended the quarter with approximately $40 million in cash, and your accounts receivable are below $10 million. It appears you faced some challenges with your suppliers this quarter, as indicated by a significant decrease in accounts payable. From my calculations, there's been about a 100-day reduction in the average time you pay your suppliers, which is common during periods of supplier unease. You still have around $96 million available under your credit line, though this is subject to certain tests. These tests look at past performance, suggesting you have the capacity to access those funds. However, it seems unlikely that you'll be able to do so after the second quarter. Given the upcoming coupon payment due in 11 days on the 2027 notes, can you clarify your current liquidity situation? Have you withdrawn more from your credit facility? Also, can you provide more details about the accounts payable issue that appears to have caused a significant cash flow loss this quarter? Finally, regarding the $75 million in VAT receipts expected this year, could you share the timing for those? Liquidity is clearly becoming an important concern.

Yes. Regarding the payables, we had a very active fourth quarter program, which led to the unwinding of those payables during the quarter. It's more of a normal situation rather than an issue with nervous suppliers; these are regular payables that we settled. Concerning liquidity, we have $204 million drawn on the reserve-based lending facility, and that amount remains unchanged. Our next results will be available 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.

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 and 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 Q2, Q3, Q4? And lastly, you talked about minimum maintenance CapEx again in $30 environments, what would that be more or less?

Yes, it's Tony here. I'll respond to the question on Q3 and Q4 production. With a price environment of $30, as Ryan mentioned, we need to better understand the implications of COVID policy changes, as this will influence our activities regarding the wells waiting for workover. Therefore, it's challenging to provide any guidance for the third and fourth quarters. Could you remind me of the second part of that question?

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

Yes. 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 future projects. 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 at 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.

No. Correct. No cash, just taxes.

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.