Good morning and welcome to the VAALCO Energy, Inc. Third Quarter 2020 Earnings Conference Call. All participants will be in listen-only mode. After today’s presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead.

Thank you. Good morning, everyone, and welcome to VAALCO Energy's Third Quarter 2020 Conference Call. After I cover the forward-looking statements, Cary Bounds, our Chief Executive Officer, will review key highlights along with operational results. Liz Prochnow, our Chief Financial Officer, will then provide a more in-depth financial review. Cary will then return for some closing comments before we take your questions. During our Q&A session, we ask you to limit your questions to one and a follow-up. You can always re-enter the queue with additional questions. I’d like to point out that we posted an updated investor deck on our website this morning that has additional financial analysis, comparisons, and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance, and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements whether as a result of new information, future events, or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday's press release, the presentation posted on our website this morning, and in the reports we filed with the SEC, including the Form 10-Q that was filed yesterday. Please note that this conference call is being recorded. Let me turn the call over to Cary.

Thank you, Al. Good morning, everyone. And welcome to our third quarter 2020 earnings conference call. This year has been difficult for the energy industry as we have faced many extraordinary challenges from COVID-19 to supply and demand imbalances to low commodity prices. VAALCO has responded well to all of these challenges. Thus far, VAALCO’s operations have not been materially impacted by the global COVID-19 pandemic, which is a testament to our dedicated workforce given that we have operated our platforms under the precautionary measures for approximately eight months now. We have managed through the logistical challenges that we have faced since the outbreak occurred and continue to put the safety of our employees, contractors, and local stakeholders first. We’re minimizing high-risk activities and using onsite medical supervision to screen, test, and monitor employees and contractors while in quarantine before going offshore. We have contingency plans in place in the event we’re directly impacted by the pandemic. We continue to work with our vendors and suppliers to implement cost-cutting measures and partner with other operators to reduce costs by sharing services and equipment such as support vessels and helicopters. As we've said before, approximately 90% of our costs are fixed, and we can add production and improve our margins with minimal increase in cost. Our strong production and lower costs have helped us to continue to generate solid cash flow and adjusted EBITDAX. We remain focused on operational excellence, which will lead to cash flow generation, allowing us to prepare for future drilling campaigns over time. In the third quarter, we produced an average of 4,405 net barrels of oil per day, which was right at the midpoint of our guidance range. Our third quarter of 2020 production was up 43% from the same quarter in 2019 as a result of the three new wells that came online as part of our successful 2019-2020 drilling program. However, our third quarter 2020 production was below our second quarter average of 5,410 net barrels of oil per day due to the planned full-field maintenance shutdown in September and the production curtailment due to an OPEC+ mandate. As we discussed in our last conference call, we were asked to assist Gabon in meeting its OPEC+ production quota by temporarily curtailing production at Etame. In September, we performed our planned five-day turnaround to perform maintenance on the Nautipa FPSO and all four production platforms. The turnaround was performed on time, on budget and, most importantly, with no safety or environmental incidents. Looking ahead, we expect to produce somewhere between 4,600 and 5,000 barrels of oil per day net to VAALCO in the fourth quarter, which is up 200 to 600 barrels of oil per day versus the third quarter. You will note that we have increased the lower end of the range for the fourth quarter in our new guidance of 4,600 to 5,000 barrels of oil per day from the 4,300 to 5,000 barrels of oil per day in that fourth quarter estimate we gave during our last call. We continue to see strong production uplift from better than expected performance from the three new development wells drilled and brought online as part of the 2019-2020 drilling campaign. In the third quarter, despite continued low realized crude oil prices and production curtailments, we recorded an adjusted EBITDAX of $7 million, which brings our year-to-date adjusted EBITDAX to $23.1 million. We have only spent about $10 million in CapEx thus far this year, thereby confirming our ability to generate free cash flow even in this difficult environment. In addition to managing our capital spending, we've also reduced our operating and G&A expenses. Liz will give more detail on this, but driving down our costs maximizes our ability to generate free cash flow. In September, we announced that we’re acquiring and processing new proprietary 3-D seismic data over the entire term license. We believe the seismic data will help improve the capital efficiency of the term by allowing us to select drilling locations that maximize oil recovery, and it will also allow us to identify new locations to add to our portfolio of drilling prospects. We expect to complete the seismic acquisition in the fourth quarter of this year, which will be processed and completed by this time next year. When acquisition and processing are complete, this will be the first continuous 3-D seismic survey to cover the entire term license, which will allow for a more robust subsurface interpretation than ever before. We're proud of the highly successful and transformational drilling program that we completed earlier this year, and we believe that a new 3-D seismic survey will build on that success as we plan for future drilling programs over time. Now, I'd like to give you a quick update on our activity in Equatorial Guinea. In the first quarter of 2020, VAALCO acquired additional working interest from Atlas Petroleum, thereby increasing our working interest from 31% to 43%. The cost for acquiring the additional Block P working interest is a future payment of $3.1 million that will only be made if there's commercial production from Block P. In August, an amendment to our production sharing contract reflecting our updated participating interest and naming us as operator was executed by the Equatorial Guinea Ministry of Mines and Hydrocarbons. We're excited about the future of Block P, and we’re having ongoing farm-out discussions with Levene HydroCarbon. Under the farm-out terms, Levene will potentially cover off or substantially all of the costs to drill an exploratory well in Block P. We’re optimistic that we will finalize the agreements with Levene and prepare for a drilling campaign that will commence in the next couple of years with minimal financial exposure to VAALCO. This is a challenging time in the energy industry, but we believe that we’re well-positioned with a strong debt-free balance sheet, $43 million in cash, and a stable production base that is free cash flow positive at current prices. Going forward, we’ll maintain our focus on free cash flow and operational excellence to deliver both near-term and long-term profitable growth. With that, I’ll turn the call over to Liz.

Thank you, Cary, and good morning, everyone. In the third quarter of 2020, we reported strong net income of $7.6 million or $0.13 per diluted share. This is despite the impact of low crude prices and temporarily lower production expense because of the maintenance shutdown and OPEC+ curtailment. In the third quarter of 2019, we reported a net loss of $3.9 million or $0.07 per diluted share. Lower realized crude oil prices from this year’s third quarter were more than offset by higher sales volumes year-over-year as a result of the additional production associated with the three successful wells from the 2019-2020 drilling program. Third quarter 2020 net income additionally benefited from lower operating costs and expenses compared with the same period last year. Third quarter 2020 earnings included a tax benefit of $2.8 million, while the same period a year ago had an income tax expense of $7.7 million. In the second quarter of 2020, net income was $0.6 million or $0.01 per diluted share, which reflected the impact of significantly lower prices that were partially offset by higher sales volumes, as well as a gain on derivatives of $0.8 million and a tax benefit of $2.2 million. Adjusted net income in the third quarter of 2020 increased to $2.3 million or $0.04 per diluted share from an adjusted net loss in the third quarter of 2019 of $0.6 million or $0.01 per share, primarily as a result of a $2.6 million decrease in G&A expense. Third quarter 2020 adjusted net income was lower than $5.3 million in the second quarter of this year, primarily because of realized gains of $6.5 million in the second quarter from our derivative contracts. Adjusted EBITDAX totaled $7 million in the third quarter of 2020 compared with $4.5 million in the same period of 2019. In the second quarter of 2020, adjusted EBITDAX was $10.1 million. Adjusted EBITDAX for this year's third quarter was higher than the same period last year primarily due to increased sales volumes associated with the new production from the three wells completed as part of the drilling program and lower operating costs and expenses, which were partially offset by lower realized prices. Adjusted EBITDAX for the third quarter of 2020 was lower than the second quarter primarily due to the realized gain on derivatives of $6.5 million mentioned earlier. Production for the third quarter of 4,405 net barrels of oil per day increased 43% from the third quarter of 2019 due to the new wells which came online, but was down 19% in the second quarter of 2020 due to the planned full field maintenance shutdown and OPEC+ curtailment. Sales volumes in the third quarter of 2020 were up 48% from the same period in 2019 because of the new wells but were down 35% in the same quarter of 2020 primarily due to the combination of lower production as well as having three listings in the third quarter versus four in the second quarter this year. Our crude oil price realizations fell 29% to $43.63 per barrel in the third quarter of 2020 versus $61.26 per barrel in the same period in 2019, a drop of 54% compared to the $28.31 per barrel in this year’s second quarter. At this time, we don't have any derivative contracts in place, but we’ll continue to assess our needs to mitigate price risk and protect cash flow in the future. Turning to expenses, production expense excluding workovers for the third quarter of 2020 was $9.1 million or $22.21 per net barrel of oil, which was within our guidance ranges. This expense was lower than $9.5 million in the same period of 2019 primarily due to proactive cost reductions, and this was offset by $0.4 million in additional costs related to proactive employee-related measures taken in response to the pandemic. Production expense for the third quarter of 2020 was lower than the $12.2 million in the second quarter of 2020 as a result of less sales volumes. Per unit production expense excluding workovers decreased significantly in the third quarter of 2020 as compared to the third quarter of 2019, as a result of higher sales volumes. For the full-year 2020, we’re looking to reduce the top end of the guidance range for our production expense excluding workovers to $38 million versus the $39 million previously reported and tightening the production expense per barrel of crude oil sales to $20.50 to $21.50. Production expense for the fourth quarter of 2020 is projected to be between $9 million and $10 million, or $19 to $23 per barrel of crude oil sales. While low crude oil prices have certainly had an impactful effect on our financial results, from an operational standpoint, we have not been materially impacted by the worldwide COVID-19 pandemic. Our guidance excludes any potential future impacts not currently being experienced. DD&A for the third quarter of 2020 was $2.2 million or $537 per net barrel of oil sales, which was about on per barrel guidance range. DD&A per barrel was substantially unchanged from the same period in 2019; the per unit DD&A rate in the third quarter of 2020 was higher than the rate in the second quarter of 2020 due to the higher volumes attributable to fields with higher depreciable cost, resulting in the per barrel rate being above our guidance range. We expect our DD&A for the fourth quarter of this year to be between $5 and $6 per net barrel sold. General and administrative expense for the third quarter of 2020, excluding non-cash stock compensation expense, was $2.4 million. G&A was lower than the $3.6 million in the third quarter of 2019 as a result of lower professional fees, legal expenses, and accounting and audit fees. That was similar to G&A expenses in the second quarter of 2020. The third quarter of 2019 included one-time G&A costs associated with our general listing on the London Stock Exchange. We’re forecasting that the lower cash G&A run rates due to proactive reductions implemented in April will also occur in the fourth quarter of 2020. As we saw for the full year 2020, we have lowered our forecasts of cash G&A to be between $10 million and $11 million. Non-cash stock-based compensation expense was a benefit of $0.2 million during the three months ended September 30, 2020, reflecting the reduction in the SARs liability as a result of a decrease in the company's stock price during the quarter; the third quarter of 2019 and the second quarter of 2020, saw our stock price increase, which resulted in charges to increase SARs liability during those periods. As for taxes, due to evaluation allowances on deferred tax assets recognized this year in combination with an overall negative effective tax rate, comparisons between quarters are challenging. For the three months ended September 30, 2020, the company had an overall income tax benefit of $2.8 million. This was comprised of a $5.3 million deferred tax benefit and a current tax expense of $2.5 million. Foreign income taxes are attributable to Gabon and are settled by the government taking their crude oil in-kind. As detailed on Slide 27 in the presentation deck posted this morning on our website, we currently estimate that VAALCO’s operational breakeven in 2020 is now approximately $26 per net barrel of oil sales and our free cash flow breakeven price is approximately $33 per net barrel of oil sales. Keep in mind that our realized prices are benchmarked to Brent crude oil prices. These breakeven prices have gone down this year due to higher production levels, as well as lower costs in general. In general terms, we estimate that each $5 increase in realized oil price increases our annual adjusted EBITDAX by approximately $9 million. This clearly shows our strong leverage to higher oil prices. At September 30, 2020, we had an unrestricted cash balance of $42 million, which included $6 million of cash attributable to non-operating joint venture under advances. Despite the challenges of low prices, adjusted working capital at September 30, 2020, increased to $29.3 million compared with $24.1 million as of June 30, 2020. In the third quarter of 2020, we had essentially minimal net capital expenditures on an accrual basis reflecting the efforts to manage expenditures in the current low oil price environment. As Cary discussed, we recently agreed to acquire new 3-D seismic data in the fourth quarter of 2020. We estimate the gross cost of the acquisition and processing of the seismic survey to be between $12 million and $15 million or $4 million to $5 million net to VAALCO. We plan to invest $3 million to $3.5 million net to VAALCO in the fourth quarter of 2020 and the balance in 2021, all of which we expect to have cash on hand and from operations. It has been the case since the second quarter of 2018; we’re carrying no debt. With this, I'll now turn the call back over to Cary.

Thanks, Liz. While the current pricing environment remains volatile, we continue to react decisively to drive down our costs and improve our margins. Over the past several years, we have worked diligently to build a solid foundation for the future. We've taken actions to strengthen VAALCO operationally and financially, including eliminating all debt and growing our production base, which will allow us to better navigate cyclical energy markets and leave us uniquely placed to consider growth opportunities. We remain focused on continuing to generate positive cash flow as we prepare for future drilling campaigns. On our term license, VAALCO has a strong producing asset in Gabon with significant upside. We hope to repeat the success of the 2019-2020 drilling program and continue adding reserves and production to the life of our term license in Gabon. We recently initiated a new 3-D seismic acquisition campaign at Etame that will conclude in the fourth quarter of 2020, with processing fully completed by the fourth quarter of 2021. This full-field 3-D survey will optimize future drilling locations, provide better imaging of existing satellite and infill locations, as well as identify additional prospects to add to our drilling portfolio. We're very excited to acquire, process and analyze the data and then incorporate it with our 20-plus years of knowledge as operator of the field. With a debt-free balance sheet, approximately $42 million in cash on hand at September 30, and a strong asset base at Etame that continues to generate free cash flow, we have positioned VAALCO to weather near-term uncertainties. Additionally, we continue to evaluate opportunities that are consistent with our inorganic growth strategy, and we believe that we’re well positioned to deliver long-term growth in line with our strategic objectives. Thank you. And with that operator, we’re ready to take questions.

We’ll now begin the question-and-answer session. The first question today comes from Charlie Sharp of Canaccord. Please go ahead.

Thank you very much and thank you, Cary and Liz for a comprehensive update, much appreciated. If I may just ask a question around the seismic and the prospectivity that you see. You highlighted the success of the 2019-2020 drilling program. I'm not looking for specific details. But perhaps you could paint a picture of the number of future well locations that you might see based upon the current interpretation of data. And also, could you just explain a little bit about the dovetailing perhaps of interpretation with fast track processing of certain areas of the new 3-D seismic? In other words, do you have to wait until all of that seismic is fully processed? Or is there a way of kind of accelerating that interpretation process? Thank you.

Right, okay. Well, Charlie, good to hear from you. I’m happy to share what our strategy is with the seismic. In our investor deck on Slide 18, you'll see a list of prospects and wells. I would focus you in on to answer your question on where we would accelerate processing, it would be in the areas where we have what we call our satellite prospects. These are prospects that were identified on the existing 3-D, where the new 3-D will give us better imaging of those prospects. That is our intention. I think the idea would be to accelerate processing where we see these satellite prospects that have, on average, reserves or resource potential of around 5 million barrels, but of course, that's the middle of the range; it could be much more than that. So, one of the primary objectives of the seismic acquisition campaign is to better define our satellite prospects. We will start processing immediately. We aim to accelerate processing around our satellite prospects and finish the final processing or fully processed data by the end of next year.

Okay, thank you.

Great, thank you. I’ll follow-on to that last question. When you began the survey, what are you speculating that you're going to determine? Are you thinking that there is a lot more oil out in those satellite prospects? Or are you really doing this more to identify precise locations for infill wells? What's your gut feeling of what you're going to find and ultimate purpose?

Right, and hi, Bill, good to hear from you as well and great question. So, the primary objective, I would say, is to define the satellite prospects and understand what the oil potential is, so we can prioritize our capital spending in the future and drill the prospect with the most confidence and the most oil. Secondary to that is better defining where to place wells in existing fields. Also, I would mention that when the government granted our license extension back in 2018, we picked up additional acreage. There are areas that we haven't really studied before, and I'm hopeful that we find additional prospects in those new areas. Those are our objectives, Bill.

That's very helpful. And your gut feeling, from what you know, is relative to the satellite prospects, what are you thinking or hoping that the issue will confirm?

What I'm thinking and hoping that we can confirm is that the probability of success is 75% or greater; we have several prospects that are at that probability of success. First, I’d like to move that up to maybe 90%. I don’t know, and then, like I said, I’m hopeful that the prospects are larger. The seismic will tell us where we have the most confidence and where we have the most potential resources.

Great, that’s appreciated. And I just used up my question. And my follow-up, would you like me to go back in the queue, or shall I continue?

Go ahead and continue Bill, that’s fine.

Great, thank you. And cut me off anytime. The G&A you referenced in the press release has been $800,000 or probably $400,000 higher as a result of COVID and the proactive things that you're doing. Is that going to go away anytime soon or basically, should we count that as an ongoing part of your expense structure as long as COVID is an issue?

You would count it as part of our ongoing cost structure as long as COVID is an issue because what we're doing is we're mitigating the impact of an outbreak on any of our facilities, which would be devastating. So I look at that cost as minimal because it has kept us enabling us to continue producing with no real impact on operations. You will see that cost continue as long as the epidemic is still running.

And also, I want to clarify that these costs are primarily in our production expense rather than G&A.

Yes, thank you. As I was asking the question, I confused it with my next one. So that's a great clarification, Liz, which is the G&A did decline $800,000 sequentially. What allowed that to happen? I mean, great job, but how did you do that?

Okay, so you're talking about overall G&A, right?

That's right, overall G&A down in Q3 versus Q2.

Yes, most of what's going on there has to do with the SARs liability. We have to mark that to market at the end of the period. So whatever the stock price is on the last day of the quarter is going to drive the valuation for that liability. When you end up with an increase in the stock price, we need to record additional expense. When you have a decrease, you record a reversal of that expense. That's largely what's going on. Beyond that, it's pretty stable between the quarters.

The only benefit one could think of is a lower stock price?

Yes, I have to say, I agree with you. I don't like clients charging for that.

I understand one other accounting question, if I may. The reduction in your tax valuation allowance with all of the uncertainty that the pandemic is causing, what gave you the confidence to reduce that valuation allowance?

I have to say, and this is just confusing, but it's part of the mechanics of U.S. GAAP rules on interim period tax allocation. There are some odd rules that you have to apply, and you end up with some situations where we've got income in some quarters and losses in others. Because we ended up with an overall negative effective tax rate, you allocate the taxes oddly versus what you would expect. I know that's probably not the most helpful answer, but it's really the best I can give for something that you almost have to be a tax expert to make sense of. Candidly, if it were me, I would change the way the rules are, because I just don't think it's helpful for the investors to see the allocations and where they are, but that's what we're stuck with. By the end of the year, I think overall it'll make sense, but on a quarterly basis, it’s challenging to understand.

And so maybe I should take this offline, but I'm going to take one more stab at it, and then I’ll move on.

Yes.

Is this an indication that you would expect greater profitability than what you were previously expecting? As a result, that’s mechanically why this needs to be done. And again, that’ll be more obvious in the fourth quarter? Or is it something entirely less logical?

It's something entirely less logical. Basically, you forecast what you thought the full year was going to be in terms of taxable income and had to allocate a portion of valuation allowance in the first quarter. We had losses using a negative rate, which put on a bigger valuation allowance in the first quarter than what we were projecting for the whole year. It reverses out over the subsequent quarters. This is a very odd result. Probably not the most helpful explanation, but that’s the best I can do.

Great. No, I appreciate it, Liz. Thank you. And then last one for me. Is the production decline in the third quarter versus the second quarter? How much of that was due to the FPSO maintenance versus how much was the OPEC component to recognize the wells themselves are producing, could produce better than what you did?

Right, the way to think about that Bill is the turnaround for maintenance on the FPSO and the platforms was a five-day turnaround. You can take the average production for the quarter and multiply by five, and that was the impact of the turnaround. The rest of the reduction was related to the OPEC curtailment, so that Gabon could meet their quotas.

Great, thank you both.

Okay, thank you.

Your next question comes from Jamie Wilen of Wilen Management. Please go ahead.

Good morning. When reading about your partner in Etame is looking to sell their minority interest, there used to be lots of buyers circling around Karyia Energy, Energy and maybe others. Could you tell me the status of that? Do we have the right of first refusal? Are we in their bidding? Do we wait until the end? And what does that say about what we think a part of this partnership is worth?

Jamie, I can't comment on Sasol’s divestiture process and who's participating and what the status is; that is really for Sasol to comment on. What I can say is yes, there is in our joint operating agreement at Etame an opportunity for not only VAALCO but the other partners to preempt the sales process. Again, I can't comment on those details because that is Sasol’s process to notify the joint venture partners. However, under our venture, there would be an opportunity for VAALCO and the other partners to preempt. Other than that, all I can say is we have repeatedly stated that we’re very happy with the Etame asset, and for the right price, we would increase our stake, whether it's Sasol, Addax or PetroEnergy, but I cannot comment on the process other than that.

Did Sasol put out any deadline dates or when they wanted to be invited?

Jamie, again, I can't comment on their process.

Okay, you mentioned when you were talking about the seismic that with the 2018 extension from Gabon that they gave you new areas. What did they give you? I didn't recall reading about that.

If you refer back to our investor deck on Slide 18, I don't know if you have access to that. But on Slide 18, there's an outline of the license today. If you go back in time, prior to the extension, we had three separate areas, AEEs. They were production areas; there was one to the Southeast that was Avouma, one in the middle that was Etame and South-East Etame, and one further to the north, that was Ebouri. They were not continuous. The acreage we picked up is the acreage in the center of the field in between Ebouri and Etame, and in between Etame and Avouma.

Excellent, good. When you put out your forecast for the fourth quarter and looking forward, how do you factor in what you may have to do to meet compliance requirements for OPEC? Also, what percentage did you cut back, do they force you to cut back because of the OPEC restrictions?

The percentage we cut back was a negotiation between VAALCO and the government. For that reason, I really cannot give you any of the details other than we worked with the Gabonese government on a target production rate for VAALCO based on VAALCO’s long-term commitment to Gabon, the wells we recently drilled. Each operator independently negotiated an allocation; I cannot comment other than that. The first question on the fourth quarter; what you'll see in our guidance ranges has the OPEC production curtailment requirements built into it. The ranges we put out, the low end of that range is up compared to the prior fourth quarter forecast. So the OPEC curtailment is already built in.

And lastly, with the next drilling program, if you're going to wait till the 3-D seismic is complete. Is this a 2022 item or a function of oil prices or where do you look at that?

There are a couple points here. We don't really have to wait till the seismic acquisition is complete. As we talked about earlier with Charlie Sharp, we will accelerate processing in certain areas where we see the most prospectivity. We don’t necessarily have to wait till all the processing is completed to identify well locations. We’ll start processing early next year and have data and survey interpreted all throughout next year. In terms of the next drilling program, the seismic survey will not slow down the timing of the next drilling program. We aim for 18 to 24 months between drilling programs, which still remains our ambition and schedule. You could think about 18 to 24 months from when we concluded the drilling program last April; that's when we would target picking up again, so that would be late next year into early 2022, something like that.

Great, thanks, Cary. Appreciate your time.

Okay, thank you, Jamie, good to hear from you.

Showing no further questions. This concludes our question-and-answer session. I would like to turn the conference back over to Cary Bounds for any closing remarks.

Yes, I wanted to thank everybody for participating, and we look forward to speaking with you again next quarter.

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.