Good day, and welcome to the Vaalco Energy fourth quarter and full year 2020 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touch-tone phone. To withdraw your question, please press star then two. Please note today's event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead, sir. Thank you, Rocco. Good morning, everyone, and welcome to Vaalco Energy's fourth quarter and full-year 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 more closing comments before we take your questions. During our question- and- answer session, we ask that you 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 investor deck this morning on our website 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 this morning on our website, and in the reports we file with the SEC, including the 10-K that we filed yesterday. Please note this call is being recorded. Let me turn the call over to Cary. Thank you, Al. Good morning, everyone, welcome to our fourth quarter and year-end 2020 earnings conference call. Before I discuss our results, I would like to reflect on a number of significant accomplishments we have achieved, all of which are building blocks toward long-term growth. In 2018, we negotiated a license extension of up to 20 years in Gabon that provided Vaalco the runway to maximize value by growing reserves and increasing production from our world-class Etame asset. Also in 2018, we paid off all our outstanding debt and began to rebuild our cash position. In 2019, we initiated trading on the London Stock Exchange, which complements our listing on the New York Stock Exchange by providing us the opportunity to diversify our shareholder base, attract additional research coverage, and provide Vaalco with access to additional sources of capital to help fund our growth objectives. Just as critical, in September of 2019, we kicked off our 2019/2020 drilling campaign. That campaign had three successful development wells and two successful appraisal well bores. Comparing our full year 2020 production of 4,853 net barrels of oil per day with our 2019 average of 3,476 net barrels of oil per day, we increased production 40% year-over-year as a result of our drilling success. In 2020, we saw oil prices adversely impacted by the global COVID-19 pandemic as well as supply and demand imbalances. We had hedges in place that provided us good protection when oil prices fell, and we were able to continue to generate meaningful cap-free cash flow from our higher production volumes in 2020. Maintaining our strong balance sheet and financial flexibility gave us the ability to capture value through a very accretive acquisition opportunity that arose in 2020. We were able to overcome the challenges in 2020 and close the acquisition of Sasol's Etame interest in February 2021 with cash on hand. With the additional production that transaction brings us, along with the strong recovery in oil pricing, we're projecting continued meaningful free cash flow generation going forward. This has provided us with the confidence to announce our next drilling campaign, which is expected to start in late 2021. We are planning to drill up to four wells that could add an additional 7,000-8,000 gross barrels of oil per day when the drilling program is completed in 2022. With our higher working interest in Etame, this could be an additional 3,500- 4,100 net barrels of oil per day to Vaalco. This is truly an exciting time for Vaalco, and we believe that we have a very bright future ahead of us as we are well on our way to achieving our long-term goals. Before I get into our operational results, I would like to review some of the key highlights of the Sasol acquisition. In November 2020, we agreed to purchase Sasol's 27.8% working interest in Etame for $44 million, with the final cash settlement amount to be reduced by net cash flows generated from the effective date of July 1 through the closing date. As part of the agreement, we made a $4.3 million cash deposit in November and agreed to a contingent payment of $5 million if Brent oil prices averaged greater than $60 per barrel for 90 consecutive days. We closed the acquisition on February 25th of this year. Taking into account the $4.3 million deposit and the cash flow that was generated between July 1, 2020, and the date of closing, we paid $29.6 million at closing, all with cash on hand. We believe the deal is very accretive to Vaalco as it is improving our margins, increasing production, and the price we paid per net barrel of oil was about $4.91 for 2P CPR reserves. Since we already operate the asset, we expect minimal increase in G&A expense, there is no integration needed, and we will immediately benefit from the acquisition. Turning to operational results. In the fourth quarter of 2020, we produced an average of 4,662 net barrels of oil per day, which was an increase of 27% over the fourth quarter of 2019, driven by our strong well results from the recent drilling campaign. For the full year, production averaged 4,853 net barrels of oil per day, an increase of 40% year-over-year. Looking ahead to 2021, I would like to spend a few minutes discussing the details of our 2021 production outlook, which includes additional volumes as a result of the Sasol acquisition. Our first quarter production will not include any Sasol volumes prior to the transaction closing date of February 25th. This means that first quarter production includes two months of Vaalco volumes and one month with Vaalco and Sasol volumes combined, which puts our first quarter 2021 guidance between 5,100 and 5,400 net barrels of oil per day. The midpoint of first quarter production guidance is a 13% increase over fourth quarter 2020 average production. Production guidance for the remainder of 2021 includes the full production impact of the Sasol acquisition. In the second quarter of 2021, our production is expected to average between 8,000 and 8,600 net barrels of oil per day. During the second half of 2021, we are planning our annual seven-day turnaround, and we are not forecasting any material production uplift from the upcoming drilling campaign. Taking into account natural decline as well, we expect the second half of 2021 to average between 7,100 and 7,800 net barrels of oil per day. Taking all of this into consideration, we expect net production to be in the range of 6,800- 7,400 net barrels of oil per day for the full year 2021. That is a year-over-year increase of 46% at the midpoint of 2021 guidance. The significant increase in 2021 production, coupled with the rising pricing environment, should help generate solid EBITDAX and enable Vaalco to grow its cash position and fund our upcoming drilling campaign from cash on hand. In the fourth quarter, we reported adjusted EBITDAX of $3.5 million. Unfortunately, our fourth quarter results were adversely impacted by a delay in oil sales from late December into early January. As a result, our fourth quarter earnings and adjusted EBITDAX were lower, but sales volumes deferred to January were priced at January Brent pricing, which was higher than December. For the full year 2020, we generated $26.6 million in adjusted EBITDAX. I would like to discuss the progress of our 3-D seismic acquisition and our plans for the next drilling campaign scheduled to start late this year. In 2020, we completed the acquisition of a new 3-D seismic survey over the entire Etame block. We expect the seismic data to enhance subsurface imaging by merging our legacy data with the newly acquired seismic, allowing for the first continuous 3-D seismic over the entire block. The improved 3-D seismic imaging will help us reduce risk and optimize future drilling locations. The success of our 2019/2020 drilling campaign has built a solid foundation for future drilling campaigns at Etame. In our prior quarterly calls, I have said that our vision is to repeat similar drilling programs and continue adding reserves and production over the next several years at Etame. With the Sasol acquisition closed, acquisition of a new 3-D seismic over the Etame block complete, and improved oil pricing, we believe the time is right to start our next drilling campaign. We are planning to drill up to four wells starting in the fourth quarter of 2021 and finishing in 2022. We are currently expecting to drill two development wells and two appraisal wells. There are opportunities for sidetrack reentries that will reduce drilling costs and access low-risk reserves and production. We also have appraisal locations that we believe could offer meaningful upside that is not currently reflected in our reserve report. The final well locations will be determined in conjunction with our processing of the new 3-D seismic data we acquired. If the four-well program is successful, the estimated increase in gross field production is 7,000 BOPD-8,000 BOPD or 3,500-4,100 net barrels of oil per day to Vaalco, when the drilling campaign is completed in 2022. The estimated cost of the program is between $115 million-$125 million gross, or $73 million-$79 million net to Vaalco. The upcoming drilling campaign has the potential to generate significant free cash flow when the current prevailing oil prices are combined with our low-cost operating structure. Our strategy is to utilize the additional free cash flow to fund inorganic transformative growth opportunities in the future. We will provide more details later as we process the seismic and finalize our well locations. Our net capital expenditures in 2020 were $20 million on a cash basis and $10.5 million on an accrual basis. Our 2020 capital expenditures were primarily related to the 2019/2020 drilling program at Etame. For the full year 2021, Vaalco estimates its net capital expenditures, excluding the 2021 drilling campaign and seismic, to total $3 million-$6 million. The full-year capital expenditure estimates also exclude any potential costs related to FPSO life extension or FPSO replacement. While there will be upfront costs associated with either replacing or extending the life of the Nautipa FPSO, we believe we will be able to lower long-term costs. I would like to spend a few minutes talking about our year-end reserves. Our year-end reserves were significantly impacted by pricing. Despite adding 1.6 million barrels as a result of positive performance revisions and the discovery of South East Etame 4P, reserves were slightly down year-over-year. The downward revisions were driven by 1.8 million barrels in production and a downward pricing revision of 1.6 million barrels. Vaalco's proved SEC reserves at December 31, 2020, were 3.2 million barrels net. The PV-10 value of these proved SEC reserves at year-end 2020 decreased to $14.7 million from $70.4 million at December 31, 2019. The 2020 SEC pricing of $42.46 was down 33% from 2019 SEC pricing of $63.60 per barrel, which drove the SEC proved PV-10 value down significantly. Our year-end 2020 2P CPR estimate of proven plus probable reserves remained virtually unchanged year-over-year at 10.4 million barrels to Vaalco's working interest. The PV-10 value of Vaalco's 2P CPR reserves at year-end 2020 was $84.4 million, assuming year-end 2020 escalated Brent pricing. Our year-end 2020 reserves were fully engineered by Vaalco's third-party independent reserve consultant, Netherland, Sewell & Associates. They are very familiar with our assets and have provided annual independent estimates of Vaalco's year-end reserves for over 15 years. Regarding the acquisition of Sasol's interest at Etame, we estimate that approximately 2.7 million barrels of proved SEC net reserves and 7.9 million barrels of 2P CPR net reserves were acquired using year-end 2020 assumptions adjusted for production. Given the recent significant increase in Brent pricing and assuming that it continues through 2021, we believe that we could see a material increase in reserves, not only due to the Sasol acquisition, but to pricing as well. I would now 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 is 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. The non-binding memorandum of understanding with Levene to cover all or substantially all of Vaalco's cost to drill an exploratory well on Block P has expired. We are evaluating alternatives to fund the cost to drill an exploratory well targeting over 160 million gross barrels of resources at our Southwest Grande prospect. We are also evaluating scenarios to develop over 16 million gross barrels of contingent resources at our Venus discovery on Block P. We remain excited about EG, and we are working to profitably exploit the resource potential. In summary, we have materially enhanced value at Vaalco over the past 12 months with a highly successful drilling campaign, an accretive acquisition, new 3-D seismic, and planning for another drilling campaign later this year. We remain committed to operational excellence while generating strong financial results. We have a strong balance sheet, and with our increased production base in a rising price environment, we should generate significant cash flow in 2021. This will provide flexibility for the future as we look to continue to grow profitably and meet our long-term growth goals. With that, I would like to turn the call over to Liz to share our financial results. Thank you, Cary. Good morning, everyone. We reported a net loss of $3.6 million or $0.06 per diluted share in the fourth quarter of 2020, which included the impact of $3.6 million in exploration expense related to the Etame seismic program during the quarter and $2.2 million of expenses related to stock-based compensation. As Cary mentioned, the lifting schedule for December 2020 was delayed to January 2021, which reduced sales volumes by approximately 155,000 bbl and revenues by approximately $7.8 million, while increasing inventory costs in the fourth quarter of 2020. For comparison purposes, in the fourth quarter of 2019, we recorded net income of $1 million, or $0.02 per diluted share, which included the impact from a non-cash charge of $3.1 million for unrealized mark-to-market losses related to our crude oil swap, expense for stock-based compensation of $0.7 million, and a $1.8 million tax benefit related to a decrease in the valuation allowance on deferred tax assets. For the third quarter of 2020, we reported net income of $7.6 million to $0.13 per diluted share, which included an income tax benefit of $2.8 million, which reflected the impact of the decreased valuation allowances on deferred tax assets of $5.3 million. Our adjusted net loss in the fourth quarter of 2020 totaled $5.6 million, or $0.10 per diluted share, as compared to adjusted net income of $5.5 million or $0.09 per diluted share for the fourth quarter of 2019. The decrease in earnings between years was mainly due to the lower revenues as a result of lower oil prices and lower sales due to the delay in the lifting schedule for 2020, coupled with the $3.6 million of seismic related to the exploration expenses in the fourth quarter of 2020. In the third quarter of 2020, Vaalco reported $2.3 million in adjusted net income, or $0.04 per diluted share. Adjusted EBITDA was $3.5 million in the fourth quarter of 2020, compared to $10.4 million in the same period of 2019. In the third quarter of 2020, adjusted EBITDA was $7 million. As with the net loss and adjusted net loss, adjusted EBITDA was impacted by the lower revenues between the fourth quarter of 2019 and the fourth quarter of 2020. This was primarily a result of lower crude oil prices, whereas between the third quarter of 2020 and the fourth quarter of 2020, this was primarily a result of lower sales volumes resulting from the delay in the lifting scheduled for this past December. Production for the fourth quarter at 4,662 net barrels of oil per day increased 27% from 3,664 net barrels of oil per day in the fourth quarter of 2019 due to the new wells which came online during 2020 from our successful 2019-2020 drilling program. Fourth quarter 2020 production was up 6% from the third quarter of 2020, which had reduced due to the planned full field maintenance shutdown, as well as OPEC+ contract fulfillment. Sales volumes in the fourth quarter of 2020 were down just 9% from the same period in 2019, as the increase in sales from the new wells coming online in 2020 mitigated the impact of the delayed lifting. The impact of the delayed lifting was a 30% decrease in revenues between the third and fourth quarter. While the delayed lifting reduced revenues for the fourth quarter of 2020, as Cary mentioned, pricing improved somewhat between December 2020 and January 2021, thereby increasing the amount ultimately realized from the lifting. Our crude oil price realization fell 36% to $42.07 per barrel in the fourth quarter of 2020, versus $65.80 per barrel in the same period in 2019, but was down just 4% compared to $43.63 per barrel in the third quarter of 2020. We didn't have any derivative contracts in place in the fourth quarter of 2020. However, this past January, we did enter into new crude oil commodity swap agreements for a total of 709,262 bbl at a dated Brent weighted average price of $53.10 per barrel for the period from and including February 2021 through January 2022. These swaps settle on a monthly basis. As Cary mentioned, we hedged a portion of our production volumes to protect cash flows, which will be used to fund our 2021-2022 drilling program. We took similar actions in 2019 before we began our 2019-2020 program. The hedges were particularly beneficial for us in 2020 when crude oil prices fell and we were wrapping up our drilling program. We will continue to assess our needs to mitigate price risks and protect cash flow in the future as we consider any additional derivative contracts. Turning to expenses. Production expense, excluding workovers for the fourth quarter 2020, was $6.6 million or $22.66 per net barrel of oil sales. This was lower than the $9.8 million in the fourth quarter of 2019 and the $9.1 million in the third quarter of 2020, primarily due to the lower sales volumes in the fourth quarter of 2020 resulting from the delayed lifting. The per-unit production expense, including workovers of $22.66 per barrel in the fourth quarter of 2020, decreased significantly as compared to the $34.70 per barrel in the fourth quarter of 2019 due to the higher overall production rates, and was in line with the per unit production expense of $22.21 per barrel in the third quarter of 2020. Included in total production expense are COVID-19 related costs incurred to protect the health and safety of the company's employees, which totaled approximately $0.4 million in the fourth quarter of 2020, and $1.6 million for the full year of 2020. For the full year of 2021, we are estimating the guidance range for our production expense, excluding workovers, to be between $69 million and $77 million, or $24.50-$29.25 per barrel of oil sales on a net revenue basis. Production expense for the first quarter of 2021 is projected to be between $16.5 million and $18.5 million, or $26-$31 per barrel of oil sales. Keep in mind that all of the guidance we are providing today includes the positive impact from the additional volumes we acquired from Sasol, effective on the day we closed, February 25th, 2021. For the first quarter of 2021, we'll include approximately two months of financial results without Sasol interest and one month with. Our production expense guidance excludes any potential future impacts from COVID-19 pandemic not currently being experienced. DD&A for the fourth quarter of 2020 was $1.3 million, or $4.37 per net barrel of oil sales, compared to $2.1 million or $6.64 per net barrel in the fourth quarter of 2019, and $2.2 million or $5.37 per barrel in the third quarter of 2020. DD&A was lower than both prior periods due to lower sales volumes in the fourth quarter of 2020, resulting from the delayed lifting. The per unit DD&A rate in the fourth quarter of 2020 was lower than the rate in the fourth quarter of 2019 due to the impairment charge taken in the first quarter of 2020, and lower than the rate in the third quarter of 2020 due to higher production volumes from fields with a smaller depletable base. General and administrative expense for the fourth quarter of 2020, excluding stock-based compensation expense, was $2.5 million, compared with $2.2 million in the same period of 2019 and $2.4 million in the third quarter of 2020. G&A expense was higher than in the same period in 2019 due to higher professional fees and legal costs, and was similar to G&A expense in the third quarter of 2020. The per unit G&A rate in the fourth quarter of 2020 of $8.73 per barrel of oil sales was higher than both the fourth quarter of 2019 and third quarter of 2020 due to the lower sales volumes as a result of the delayed listing. For the full year of 2020, we are forecasting G&A to be between $10 million and $12 million, essentially unchanged from 2020, despite the large increase in production from the Sasol acquisition. While our total G&A expense isn't materially different in 2021, our G& \A per barrel in 2021 will be substantially less at about $4 per barrel at the midpoint of guidance starting in Q2, compared with $6.57 per barrel in 2020. Stock-based compensation expense was $2.2 million during the three months ended December 31st of 2020, primarily due to the increase in the SARs liability as a result of the increase in the company's stock price during the quarter. For the fourth quarter of 2020, stock-based expense related to SARs was an expense of $1.9 million, compared to an expense of $0.6 million in the fourth quarter of 2019. In the third quarter of 2020, a benefit of $0.6 million was recognized for stock-based compensation related to SARs due to the decrease in the stock price during that quarter. Turning now to taxes. Income tax was a benefit for both the fourth and third quarters of 2020. For the three months ended December 31st, 2020, income tax was a benefit of $0.8 million and included a deferred tax benefit of $2.8 million. For the three months ended September 30th, 2020, income tax was a benefit of $2.8 million and included a $5.3 million deferred tax benefit related to a decrease in valuation allowances on U.S. and Gabonese deferred tax assets. Income tax expense for the fourth quarter of 2019 was $4.2 million, which included $1.8 million of deferred tax expense rather than a benefit. Foreign income taxes are attributable to Gabon and are settled by the government by taking their crude oil in kind. As detailed on slide 28 in the presentation deck posted this morning on our website, we currently estimate that Vaalco's operational breakeven price for 2021 is now approximately $32.25 per net barrel of oil sales, and our free cash flow breakeven price is approximately $38.75 per net barrel of oil sales. Keep in mind that our realized prices are benchmarked to crude oil prices. These breakeven prices increased over 2020, primarily as a result of lower production rates reflecting natural decline. In addition, we have two workovers planned as compared to one in 2020. These estimates include the impact of our hedges. In general terms, we estimate that each $5 increase in realized oil prices increases our annual adjusted EBITDA by approximately $14 million. This clearly shows our strong leverage to higher oil prices. At year-end 2020, we had an unrestricted cash balance of $47.9 million, which includes $1.4 million of net joint venture other advances. Working capital at December 31st, 2020, was $11.4 million, compared with $16.6 million at September 30th, 2020. While adjusted working capital at December 31st, 2020, totaled $24.3 million as compared with $29.3 million at September 30th, 2020. For the full year 2020, net capital expenditures totaled $20 million on a cash basis and $10.5 million on an accrual basis. Our capital expenditures primarily related to the 2019-2020 drilling program at Etame. As has been the case since the second quarter of 2018, we are carrying no debt. With this, I will turn the call back over to Cary. Thanks, Liz. Over the past several years, we have weathered a difficult macro environment. During that time, we worked diligently to build a solid foundation for the future by strengthening Vaalco operationally and financially. This included eliminating debt, growing our production base, and consistently generating positive cash flow. As I look at 2021 and beyond, I believe that this is a very exciting time for Vaalco. We are profitably growing Vaalco through accretive acquisitions and successful drilling campaigns at Etame. We are in an improving commodity price environment, which should meaningfully assist in our ability to generate significant free cash flow. The closing of the Sasol acquisition underscores our belief in Etame as a strong producing asset with significant upside. We are also processing and interpreting our newly acquired 3-D seismic and will incorporate it with our 20+ years of knowledge as operator at Etame. The new seismic will help us to optimize and de-risk future drilling locations and potentially identify new ones. I know that I've told this story before, but I think it is worth reminding everyone of the Vaalco track record of success at Etame. When we first began producing Etame in 2002, our third-party reserve auditors estimated there was 30 million barrels of gross recoverable oil. Over the years, we have drilled and expanded Etame such that we have produced over 120 million gross barrels of oil thus far. Looking to the future, we believe that the field still has over 100 million gross barrels of resource potential. We're planning to drill up to four wells in the upcoming drilling campaign that we expect to initiate in the fourth quarter of this year. We have a strong asset base at Etame that is generating meaningful free cash flow in the current pricing environment. Additionally, we continue to evaluate opportunities that are consistent with our inorganic growth strategy, and we believe that we are well-positioned to deliver long-term growth in line with our strategic objectives. Before I close out the call, I would like to discuss our commitment to ESG. At Vaalco, we are committed to developing and producing oil resources in West Africa in a safe and environmentally responsible manner. Last year, we issued our inaugural sustainability report, which focused on our community involvement, governance practices, and environmental commitment. In 2020, we created an employee committee charged with the responsibility of monitoring adherence to our ESG standards and formally communicating findings on an ongoing basis to our Board. Also in 2020, our Board's nominating and corporate governance committee amended its charter to include the oversight of the company's policies and programs on issues of social responsibility and environmental sustainability. Our Board has empowered our management team to create a working environment that assures our success as a trusted operator, a generous partner to the communities where we operate, and as good stewards to the environment. Our 2020 ESG report will be released next month and posted to our website. It will include three years of key ESG sustainability metrics developed specifically for our industry. We believe that Vaalco has a bright future, and we remain committed to sustainably developing our robust asset base. Thank you. With that operator, we are ready to take questions. Thank you. We will now begin the question- and- answer session. To ask a question, you may press star then one on a touchtone phone. If you're using a speakerphone, we ask that you please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Today's first question comes from Stephane Foucaud with Auctus Advisors. Please go ahead. Hi, guys. Two questions for me, a bit detailed. The first one is around the 2C contingent resources, particularly I saw that the extension based on economics sort of moved from 13 million barrel to 18 million barrel. Even those are quite some low-risk resources, it's just about extending the contract. I was wondering whether you could provide some color on why that has jumped up so much. The second one is a simple one. It's just I saw that there is an increase in the payables, I think something that you call the account with JV partners. I think there's $5 million. I was wondering how the cash CapEx would move in Q1, and if whether it would be, we need to incorporate this $5 million payment on top of the $2 million-$3 million, I think, that you have forecasted in CapEx for Q1. Thank you. Okay, Stephane. Great to hear from you. I will answer your first question and then your second question, I'll revert over to Liz. Your first question on contingent resources related to license extension beyond 2028, and the change from 30 million barrels to 18 million barrels of contingent resources. What happened is, that 30 million barrels was actually split into a combination of contingent and prospective resources. You'll see that there's another I'm sorry. That's not correct. I'm sorry. We have a management estimate of prospective resources that we haven't included on the table, but those contingent resources that you see for the extension, based on economics, those are Netherland, Sewell numbers. As we get our arms around the seismic and the interpretation of the seismic and we come up with new interpretations of the subsurface, we will revise our internal estimates and work with Netherland, Sewell next year to bring those volumes back into contingent. Again, those are barrels that would have been produced from 2028 to 2038, and in our view, they're prospective, and we will revisit those reserves as we continue to evaluate our seismic. On your second question. Yeah, Stephane, on the second question, the joint venture, its payables and receivables are really a function of when they're paying their cash calls. We actually had a receivable as well that was fairly large at year-end, and so the net of those two was a $1.4 million payable. Yes, those do even out over time. If we were perfect at doing our cash calls and if the joint owners didn't pay early, that number would be zero. Well, it never is, because you're never perfect at forecasting that stuff. Over time, it does tend towards zero. I would say at year-end, the $1.4 million, that's a pretty small amount of impact on cash flow in the future. Okay. Thank you. Our next question today comes from Michael Santavo with Ancoria. Please go ahead. Hi, good morning. Thanks for taking my question. I have a couple of questions. One on costs. I'd like to focus on page 28 of your deck, those cylinders, and compare, I'm not sure if you have this available, with page eight of your December deck, where the orange piece of the puzzle was $21.13 back in December. Now it's gone to $26. Just curious, I know you went over a bunch of numbers down on the cost side, and I couldn't really decipher them, but would love to know what the reason for the $5 increase from your December numbers to the deck you put out today, which this one, I believe, includes the Sasol acquisition. Yes. That's correct. Really what's driving most of that increase is the lower production volumes. About 90% of our OpEx is fixed, when the production volumes go down, the per barrel amount is going to go up and vice versa. We saw a really nice decline in 2020 due to the drilling program. Well, we had natural decline from the field, this year, because we're not doing another program, and we won't be bringing on new production until very late in the year, maybe in the following year, you don't see the benefit. That per barrel amount is going to go up. Now, on an absolute basis, our production expense is expected to be comparable between the two years, and I think the midpoint of our guidance would point you to that. Part of this is challenging because you've got the mixture of a portion of the year being with and without Sasol. What we did in the press release is we gave the gross numbers between the two years, and we discussed those, and you'll see that the midpoint of the guidance is close to what the gross number was last year. Okay. Your decline rate of 15% 2021- 2026 is a lot more than a 15% increase on a per barrel basis. Is there something else going on there? Is there cost inflation compared to- It's about $4 of the increase is the production rate. There is a little bit of increase overall in production expense, but not a significant amount. The other thing that you need to take into consideration is the prices that we're using here. There is a bit of a change. At slightly higher oil prices, you can end up with slightly higher production expense as well, because there's 10% of it that is variable. Okay. The other pieces of the puzzle have also gone up. The tax has gone up at $55 from December to today's deck by a little bit, and then the G&A has gone up as well, and workovers has gone up. Everything seems to have gone up. Is there a reason for that? If you're talking about on a per barrel basis. Yes The tax is going to be a function of our revenues. In general, and this isn't 100%, but in general, the cash tax that we pay is going to run about 10% of our revenue number. The reason for that is that we're getting 80% is deductible, it's cost recovery. That leaves you with 20%, and we pay about 50% of that is paid as tax, roughly. When you're looking at a $65 oil price, you're going to end up with a higher tax number per barrel, just de facto, because you've got a higher oil price. In terms of the G&A, it's actually down on a per barrel basis from last year. Last year, I think we had $6.57 per barrel of G&A cost, and here we're forecasting about $4 per barrel at G&A cost. The December deck showed $3.44. It had a pre and post, before acquisition, after acquisition. Today it's $4. That's a pretty significant percent increase in that slice of the pie. Yeah. That's going to be more a function of the lower volumes in 2021. Okay. Let me ask my next question, if I can. Where do you think the stack looks after your 2021 and 2022 drilling program, and where does your breakeven free cash flow go from and to? We haven't given any guidance on that, but one thing I can tell you is, so for example, last drilling program, there's a slide that shows the uplift, and that was about 6,900 bpd growth. Okay? Cary mentioned in his comments, and it's also in the press release from the next program, we're expecting an uplift after the program's completed of somewhere between 7,000 bpd and 8,000 bpd growth. You can use that as a guide to help you understand, okay, what would 2022 look like with those additional barrels? Obviously, it's going to have a significant impact comparable to what we saw in the 2019- 2020 drilling program. We haven't given any guidance for 2022 yet. That should help you at least directionally understand where the per barrel costs are going. Okay. My final question will be just calculating free cash flow over the course of the year and putting that up against the Vaalco portion of the CapEx program, the drilling program 2021, 2022, that starts later this year. Do you have enough cash, I guess, between cash on hand and cash being generated, it looks like you're going to be okay, or do you plan on tapping a bank? No. Based on current oil pricing, we expect to fund the next drilling campaign from cash on hand. Okay. The hedging will protect some of that as well, you're saying? Yes. That is exactly why we put the hedging in place. Correct. Are you layering in more hedges as we speak kind of thing? Are we going to? Not as we speak. I'm sorry I interrupted you. We're not layering any hedges, not right now layering on any new hedges. Not right now, but we are always considering new hedges. Okay. All right. Great. Thanks. I'll yield the floor. Thank you. Thank you. Our next question comes from Bill Dezellem with Tieton Capital. Please go ahead. Thank you. A couple of questions. First of all, can you discuss the December lifting and why it was delayed to January? Secondarily, because oil prices did go up in January versus December, how much was the benefit to you? Sure. Hi, Bill. Thanks for the questions. Okay. The delay in the lifting or the delay in the December sales to January was a function of a couple of things. First, it was a function of the COVID-19 protocols we have in place. There was a concern right before the lifting started that there was an infected person on the FPSO. As it turns out, the person was not infected. It was a false positive. With all of our precautions that we have in place, it was more important to keep our employees safe and healthy, and we decided to pause and delay the lifting until we were certain that, again, our employees were safe and healthy. That was the initial delay. Secondarily, there were some operational issues. We had a crane that was not working on a support vessel. Not a crane, but a winch. I'm sorry. A winch that was not properly functioning on a support vessel that cost us a few days. Really the delay from December to January was primarily the COVID-19 protocols and our commitment to keep our employees safe. The benefit? The benefit was $5 a barrel. That's right. The average price, if we had done it in December, the average would have been $50. That's what we indicated with the $7.8 million and the 155,000 bbl. January prices ended up being $55. Roughly, that's $700,000-$800,000 benefit for us. Excellent. Congratulations, I guess, on not having the positive COVID and an extra three-quarters of a million in your pocket. Yes. Yeah. All right. Thank you, Bill. I apologize, Mr. Dezellem. Please rejoin the queue. In the meantime, our next question today is from Charlie Sharp with Canaccord. Please go ahead. Yes, good morning. Thank you very much for a comprehensive update this morning. Really appreciate that. A couple of questions, if I may. One is, I think, exploring a little bit more an earlier question regarding the development program that you have coming up, the drilling program at the end of this year and into next year. Perhaps asking the same question as the earlier question, but in a slightly different way. What oil price do you think you need, given the outlook for production and the cost structure you have at the moment, to be able to finance fully that program? That's one question. Secondly, with the FPSO contract expiring late next year, should we be concerned about potential uplift in cost structure associated with a replacement or an extension of that? Thank you. Okay. On the drilling campaign, at the current oil prices that we see, we should be able to fund that easily with cash on hand and cash flow being generated between now and the time of the program. While we haven't disclosed a break-even oil price or anything like that, we're happy with the current oil prices from a funding perspective. On the FPSO, Charlie, good to hear from you. You're correct. Our FPSO contract is expiring next year in September. We're looking at a couple of alternatives, either, like you mentioned, replacing the FPSO or extending the life of the existing FPSO, which is the Nautipa FPSO. I will say that both of those options require some upfront costs. Of course, if we replace the FPSO, there's installation costs and things, and then if we keep the Nautipa on station, there are life extension costs. We're working through those cost estimates now, and we have not made a decision, but as soon as we've made a decision on which path we will take, we will disclose those upfront costs. There are upfront costs, but I'll say that we do expect long-term costs to be less. In a nutshell, there will be some upfront costs, but long-term, we expect costs to be lower. That's great. Thank you. Our next question today is from Bill Dezellem with Tieton Capital. Please go ahead again, sir. Thank you. Circling back to the drilling program. I want to make sure that we're getting this right, that if we look at your forecasted production for 2021 at the midpoint, and your forecasted production from the drilling program at the midpoint, are we doing the math correctly that that's approximately a 60% increase in production? Yeah. I think mechanically that's correct. However, the 7,000 bbl-8,000 bbl is the production rate at the end of the program. You're going to have to look at 2022 on a full year basis. Obviously, you're not going to get that production for the entire year. You're going to get it at the end of the program. One of the reasons we didn't try to give 2022 production because at this point, we're forecasting we're going to start the program in December, late in 2021. There could be some things that could shift that forward or shift it back, depending on the rig contracts that we enter into and other things. At this point, it would be very difficult to give you full year production rates for 2022. Understood. Mechanically, that if the drilling program, if we were to just look at it in isolation relative to the 2021 production, it is that roughly 60% increase. The 2022 production relative to 2021 will simply be a function of the timing of when that program comes into play and natural decline rates. Yes. Exactly. Don't forget the natural decline because the existing wells will continue to decline over time in 2022. That's very helpful. Just as a reminder for us, and I apologize for not knowing this off the top of my head, what was that equivalent mechanical calculation with your last drilling program? This seems larger to me and just is really a big production benefit. On slide 10 in the deck, that gives you a good view that for 2019, we had, on a gross basis, 12,800 bpd. The uplift was 6,900 bpd, roughly. We ended up with 1,800 bpd. That was a decline. 1,800 bpd is not quite 15%, but it's a little bit less than that. We ended up, the overall average for the year was just below 18,000 bpd. Great. Thank you. I had not seen that slide. Just again, I did the math quickly. The prior program was slightly less, meaning that this new program is slightly more in terms of that mechanical calculation. Yes. Excellent. The follow on here, do you need to expand the capacity of the FPSO, whether it be the one on site or a new one, to accommodate this significant increase in production that is forthcoming? Well, we are, of course, looking into the design of a replacement vessel, we would maximize the production capacity. There's other alternatives as well, yes. The production capacity of the FPSO is definitely under consideration. Not only the production capacity, but the storage capacity. We want plenty of storage if we're producing at high rates. You're right, Bill. All of those are under consideration right now and part of the analysis that's ongoing. Well, congratulations, and thank you. Okay. Thank you, Bill. Our next question today comes from Garrett King with Truffle Hound Capital. Please go ahead. Hi, guys. Congratulations on the quarter, and again on the deal, which looks like it was just an outstanding acquisition for you guys. Thank you, Garrett. One question I had is the 10-K states the cost recovery account is at $51 million. Should we expect that to increase in conjunction with the closing of the Sasol deal? We would acquire Sasol's share of that. This is subject to certain adjustments and things. We don't have the precise number, but there should be an increase, yes. Should it be in the ballpark of 80% or? There's a lot of factors that go into it, candidly. There's limitations depending on what you pay for it and the value at the time. I will keep it in mind that that's of interest to people, so that when we make our disclosures in the first quarter, we can consider adding that. It should go up, but I can't comment on whether it's going to be an 80% increase or not. Understood. Okay. For the FPSO, in the 10-K, it states that it could process approximately 25,000 bbl- 30,000 bbl of fluids per day. Is the right way to think about it that the capacity for this vessel is 25,000 gross barrels- 30,000 gross barrels of production per day? Right. The way to think about it is the capacity is 25,000 BOPD, plus we could send through another 5,000 bbl of water per day. It's 25,000 BOPD or 30,000 bbl of a combination of oil and water. Keep in mind that we have processing capacity on all four of our platforms. We've removed the majority of the water on our platforms. The way to think about it is there's 25,000 BOPD production capacity on the FPSO. Understood. Okay. Gross, the Etame has been running, in your slide, you have it peaking out in the early part of 2020 at around 20,000 bbl, then going up to maybe 22,000 bbl later in 2022. It still seems like there is excess capacity on the vessel, which provides a lot of leverage for you guys to the extent that you can increase production and fill it. Potentially, if you feel like that's not realistic, getting a smaller vessel when the lease expires. Is that how you're thinking about it? Well, the way we're thinking about it is, you're right. We've managed over the past 20 years to drill and produce the field at between 15,000 bpd and 25,000 bpd, trying to utilize the full capacity. Now, going forward, like you mentioned, September of next year, we will either replace or extend the Nautipa. Our ambition is to increase capacity next September. That's our ambition, but it has to come at the right price. We have to look at what is the cost of increasing the capacity versus the possibilities that we have to fill that capacity. All of that is under consideration, but I would say we would lean towards increasing the capacity as of next September. Okay. It sounds like you said that you thought the total cost should decrease. Is there any reason to think the lease is significantly above or below market? Or is it sort of reset to market rates with these recent extensions? Well, the overall market is not as active as it was 20 years ago when we installed the FPSO. Again, I think it was 2012, when we amended the contract. What we're looking at again is we will have some upfront costs, but in this current market, we see the opportunity to reduce costs long term. Understood. Just looking at your slide on the deal, you guys paid $44 million. $4 million of that was a deposit, that was the agreed price. The cash that you're paying is going to be $30 million. The way I look at that is that this generated $10 million in cash in an eight-month period at $49 Brent. That's three times the cash you're paying. Brent obviously is a lot higher now. That just seems like an incredible deal. I think the other thing to keep in mind is that during that time period, we had the seismic program. That $10 million was offset by a quarter of seismic. If you excluded the seismic, and you were looking more purely at ongoing operating costs, the number would have been higher. Wow, okay. All right. Well, that's just a great deal, and it's a wonderful deal for shareholders. We commend you guys. Thank you. Thank you. We appreciate the feedback. Our next question today is a follow-up from Stephane Foucaud with Auctus Advisors. Please go ahead. Yes. Hi again, guys. Two further questions for me. Can you say anything more on the plan for Block P? The memorandum of understanding for the farm out has expired, but that still remain basically very interesting asset. Oil price is much higher, which probably means that even smaller resources are probably more commercial than they looked just six months ago. How are you seeing the sequence of events for the block, and what are your thought process? Secondly, another simple one. I was again looking at the hedging program, the $53 barrel, that's fixed price or that's floor? If you can please remind me. Thank you. Okay, Stephane. Thanks for the questions. On Block P, you're correct. The memorandum of understanding we have with Levene has expired, and that was an agreement for Levene to come in and carry us on the cost of an exploration well. Those discussions are still underway with Levene, but since the MOU has expired, we've broadened the discussions with other companies. There's a couple of different outcomes. One outcome that we're still pursuing is to find a partner to carry us on an exploration well. We're certainly still pursuing that option. You're correct at these higher oil prices. Another option that we have under evaluation is executing a standalone development of the Venus discovery on Block P. Right now we're evaluating both of those options. We haven't committed to either one yet, but they're both very robust options. Like I've said in my earlier comments, the Venus discovery on Block P is 16 million barrels of gross resources, we're looking for and evaluating cost-effective development alternatives or opportunities, I should say, in the event we don't drill an exploration well, in the event we can't find a partner to fund us. That is the state of play for Block P in Equatorial Guinea. If you don't mind, Stephane, could you repeat your second question for us? That was around the hedging program. It's a detailed question, if you could remind me whether the $50-ish per barrel is a fixed price or whether it's just a floor so that we can still benefit from the upside and the current oil price for the volume that It's a swap, so it's a fixed price of $53.10. Okay. Thank you. Back on Block P. Cary, is your feeling that Levene is still a serious counterparty? If it is not, do you get any sort of expression of interest from alternate parties? Is there the risk you might start again from scratch on the exploration farm out? On the exploration side, I can't really comment on the interest in other parties. We're still negotiating and talking to other parties. At this stage, I can't comment on the level of interest. I would say that Levene, I can't speak for what's happening internally with Levene and their management and their strategy. I can say that they chose not to extend the MOU, that we had with them to get to an agreement or to help us reach a farm-out agreement. Clearly their level of interest has changed. They have not extended the MOU, we are still in discussions with Levene. Thank you. Ladies and gentlemen, this concludes the question- and- answer session. I'd like to turn the conference back over to the management team for any final remarks. Sure. Thank you, operator. I just want to say thank you for everyone's interest, and we look forward to your participation in our next earnings call. Goodbye for now. Thank you, sir. This concludes today's conference call. You may all disconnect your lines and have a wonderful day.