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 analysts and institutions. Instructions will be provided at that time for you to queue all for questions. I would like to remind everyone that this conference call is being webcast and recorded today, Wednesday, August 5, 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, 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 for the first quarter, 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 continue to enhance and monitor our COVID-19 safety measures to ensure the health and protection of our communities, 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 beyond. I'll now turn the call over to 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 for routine mechanical workovers. The suspension of production at Suroriente in PUD 7 blocks in the Southern Putumayo region due to a force majeure led 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 reductions are structural 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 costs to be 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 were 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 a 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 non-cash impairment of $398 million on the company's oil and gas properties as a result of significantly lower oil prices. Adjusted EBITDA was $18 million with funds from operations being $6 million. With this year's oil price volatility and logistical challenges of COVID-19, Gran Tierra elected to significantly reduce the quarter's activity levels, preserve liquidity, and maintain 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 protection against the near-term low-price environment by securing a three-way Brent collar, which amounts to a total of 11,000 BOEs per day 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 and G&A costs, and we are 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.

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 want to note that the evolving situation with the COVID-19 pandemic may impact the timing of the planned activities, along with 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 offline wells are expected to be worked over to restore production by the end of 2020. 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 year-end 2020. These new wells are expected to begin production during the first quarter of 2021. The drilling rig is forecasted 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 based on the 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 the fourth quarter of 2020 to work over two to four wells at Costayaco/Vonu. At Suroriente, the restart of this block is anticipated 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 second half of 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 while optimizing the ultimate recovery of 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.

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

Yes, good morning everyone. I have three questions, if that's alright. I'll list them and then you can respond. You've provided CapEx guidance for the second half, but there hasn't been much indication regarding the cost of the wells. Could you offer some insight on that? Also, could you clarify the costs of the workovers to help us understand why OpEx may be higher in Q4 compared to Q2 and Q3? Lastly, you've shared good information regarding tax rebates or receivables. I'm curious about current liabilities and how significant of a burden they could be in the second half. Thank you.

Al, it's Tony here. I'll take the first two, and I'll let Ryan take the last one. So, the cost of wells in Acordionero for drilling new wells, we're estimating around $2.5 million to drill, complete, and equip. As mentioned, that's a significant reduction from 2019 and shows 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. All of these are, obviously, OpEx-related workovers, so per well, it's kind of in that $800,000 to $1 million range, depending on the scope of work for each well.

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

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, are the current liabilities a reasonable size?

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

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?

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.

Thank you, guys.

Thanks, Al.

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

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?

Yes. I think just on the asset impairment, it 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 based on the trailing 12 months. So, it's really just a calculation for the price since the first day of the trailing 12 months. And there typically is a disconnect between the reserve valuators and our value, especially when you have a large spread between your 1P and your 2P reserves. Unfortunately, we can only use our 1P reserves.

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

No.

Okay, great. Thanks.

Thanks.

Please go ahead.

Good morning. Thank you for taking my question. I would like some assistance in understanding the cash flow numbers. We have figures such as the EBITDA of $18 million and the proceeds from hedges totaling $17 million in the first half. Additionally, there is a tax refund of $25 million and the interest CapEx, which I don't think we have clear information on yet. It's still challenging to see how we transition from EBITDA generation to free cash flow, considering the finance cash flow from operations and CapEx is about $2 million. We also need to reconcile that with a cash decline of around $22 million without a significant change. If you could help clarify these differences, it would be greatly appreciated.

Yes, to clarify the transition from EBITDA to our reported fund flow number, the main difference is the adjusted EBITDA less the interest for the quarter. This leads us to the funds flow figure we mentioned. Additionally, regarding the change in working capital, the most significant change was a decrease in cash; however, this was primarily driven by a substantial increase in accounts receivable, which is a cash outflow. By the end of March, our accounts receivable was approximately $7 million, and we experienced about a $15 million change due to higher oil prices in June. That revenue was received in July. Furthermore, we observed a notable reduction in our payable balance.

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.

Yes, we don't forecast cash position in our guidance. Our guidance looks at my last comment on the guidance being fluid based on the ground realities of COVID-19. We need to ensure that we keep our employees and the communities that we operate in safe, and we're doing that. It's a staggered program and a cautious program, and the last thing we want to do is, as I put it, put our contractors, employees, and communities at risk.

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

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 all else being equal, if everything remains the same, that would be additive to our cash position.

Okay, perfect. Thank you very much.

Thank you.

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

Yes, good morning, gentlemen. Just to follow-up on the 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 works particularly with all the uncertainties that you have been describing.

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 from $25 million to $35 million. So that's not at the fuel level, that's at the corporate level. That's after interest, after G&A, et cetera.

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.

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

Okay. That’s great. Thank you.

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

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?

Correct. Correct. And so not just 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.

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

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, how do you expect working capital to evolve over the next quarters? And my next question is related to your current cash levels? Thank you.

Okay. On the first point, all the guidance that we have is what's in the press release. And so, really, the number one driver on that is Brent price. What we've done is we've tried to be very transparent and lay out all the activities that we want to do. The biggest change is in the timing of those activities. To give all of our stakeholders an idea as far as the productive capacity of the assets that's laid out in the press release. On working capital movements, our accounts payable 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 additional VAT refunds in July which were used to reduce payables. We’ll have the current cash balance once we put out our Q3 results, but I wouldn't expect a significant change.

Okay. Thanks.

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

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 those back? Like in Canada, 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 U.S.? And what price do you need, $50, $55, $60 Brent, to start seeing that impairment reversal?

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

Okay. Okay. And then for Gary, with the problems with the farmers still ongoing and the production, is this more of a political issue where Colombia is not getting money from the states? Is it almost like it will drag out past the U.S. election? 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 Colombia can resolve internally?

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 to help the farmers move to a different crop, a substitution program. The issue has been being able to sit down and talk. We participate in that. We help support the government with the programs. So, I don't think that it's really, Josef, related to the U.S. election. I think it's more about being able to have face-to-face discussions, and they are ongoing. They've been reinitiated. 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. Thus, we're confident that it will be something that can be managed regardless of what happens in the U.S. election.

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

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

Okay. Super. Thanks very much, guys.

Thanks.

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

Hi. Thanks for taking my question. I have a question about your covenants and the renegotiated bank agreements. Can you provide more details on what those covenants will be in 2021 and what your current leverage to EBITDAX ratio is as of the second quarter of 2020? Also, are there any step-downs required for 2021? Thanks.

Yes. The key point is that we have a lot of detail in our debt note. The total debt-to-EBITDA ratio was previously four times, and we have received covenant relief until October 1, which means we won't need to do the calculation until the end of the year. Therefore, we will need to be in compliance by the end of 2021. If we find ourselves in a more favorable oil pricing environment and are confident that we will exceed the covenant, we can potentially exit the covenant early.

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

No. Our trailing 12 months adjusted EBITDA was about four times.

Trailing 12 months, okay. And then…

Everything is on a trailing basis.

Okay. So are you expecting that to increase, as I calculated your forecasted EBITDA for 2020 based on your guidance to be around seven times or slightly more than that? Is that accurate?

Yes, because we have some of the higher EBITDA quarters from 2019 coming to an end, which will be replaced by a lower price environment in 2020.

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

Correct. And it mainly comes with the credit facility.

Okay. Thanks.

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

Okay. Thanks very much.

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

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