VAALCO Energy - Earnings Call - Q4 2020
March 10, 2021
Transcript
Speaker 0
Good day, and welcome to the VAALCO Energy Fourth Quarter and Full Year twenty twenty 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, 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.
Speaker 1
Thank you, Rocco. Good morning, everyone, and welcome to VAALCO Energy's fourth quarter and full year twenty twenty conference call. After I cover the forward looking statements, Carrie 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. Carrie 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 reenter 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 Carey.
Speaker 2
Thank you, Al. Good morning, everyone, and welcome to our fourth quarter and year end twenty twenty 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 twenty 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 2019, we kicked off our twenty nineteen-twenty twenty drilling campaign. That campaign had three successful development wells and two successful appraisal wellbores. 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 nineteen 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 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 are 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 twenty twenty one.
We are planning to drill up to four wells that could add an additional 7,000 to 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 to 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 all 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 $44,000,000 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 $4,300,000 cash deposit in November and agreed to a contingent payment of $5,000,000 if Brent oil prices averaged greater than $60 per barrel for ninety consecutive days. We closed the acquisition on February 25, taking into account the $4300000.04300000.0 dollar deposit and the cash flow that was generated between 07/01/2020 and the date of closing, we paid $29,600,000 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 and A expense. There is no integration needed, and we will immediately benefit from the acquisition.
Turning to operational results. In the 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 twenty nineteen, 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 25.
This means that first quarter production includes two months of VAALCO volumes and one month with VAALCO and Sasol ol volumes combined, which puts our first quarter twenty twenty one guidance between five thousand one hundred and five thousand four hundred net barrels of oil per day. The midpoint of first quarter production guidance is a 13% increase over fourth quarter twenty twenty average production. Production guidance for the remainder of 2021 includes the full production impact of the Sasol acquisition. In the 2021, our production is expected to average between eight thousand and eight thousand six hundred net barrels of oil per day. During the 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 twenty twenty one to average between seventy one hundred and seventy eight hundred net barrels of oil per day. Taking all of this into consideration, we we expect net production to be in the range of 6,800 to 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 $3,500,000 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 $26,600,000 in adjusted EBITDAX. Now I would like to discuss the progress of our three 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 three 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 three d seismic over the entire block.
The improved three d seismic imaging will help us reduce risk and optimize future future drilling locations. The success of our twenty nineteen, twenty twenty drilling campaign has built a solid foundation for future drilling campaigns at 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 three 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 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 three d seismic data we acquired. If the four well program successful, the estimated increase in gross fuel production is 7,000 to 8,000 barrels per barrels of oil per day or 3,500 to 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 115,000,000 and $125,000,000 gross or $73,000,000 upcoming drilling campaign has the potential to generate significant free cash flow to 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 $20,000,000 on a cash basis and $10,500,000 on an accrual basis. Our 2020 capital expenditures were primarily related to the twenty nineteen, twenty twenty drilling program at Etame. For the full year 2021, VAALCO estimates its net capital expenditures, excluding the 2021 drilling campaign and seismic, to total 3,000,000 to $6,000,000.
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 Natifa FPSO, we believe we will be able to lower long term costs. Next, 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 1,600,000 barrels as a result of positive performance revisions and the discovery at Southeast Etame 4P, reserves were slightly down year over year.
The downward revisions were driven by 1,800,000 barrels production and a downward pricing revision of 1,600,000 barrels. VAALCO's proved SEC reserves at 12/31/2020, were 3,200,000 barrels net. The PV-ten value of these proved SEC reserves at year end 2020 decreased to $14,700,000 from $70,400,000 at December 3139. The twenty twenty s e 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 2022 p CPR estimate of proven plus probable reserves remained virtually unchanged year over year at 10,400,000 barrels to VAALCO's working interest.
The PV-ten value of VAALCO's 2P CPR reserves at year end 2020 was $84,400,000 assuming year end 2020 escalated Brent pricing. Our year end 2020 reserves were fully engineered by VAALCO's third party independent reserve consultant, Netherlands Whirl and Associates. They are very familiar with our assets and have provided annual independent estimates of VAALCO's year end reserves for over 15. Regarding the acquisition of Sasol's interest at Etame, we estimate that approximately 2,700,000 barrels of proved SEC net reserves and 7,900,000 barrels of 2P CPR net reserves were acquired using year end twenty twenty 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 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 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 $3,100,000 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 operator was executed by the Equatorial Guinea Ministry of Mines and hydrocarbons. The nonbinding memorandum of understanding with Levine 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 160,000,000 gross barrels of resources at our Southwest Grande prospect. We are also evaluating scenarios to develop over 16,000,000 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 twelve months with a highly successful drilling campaign and accretive acquisition, new three 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 with our increased and 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.
Speaker 3
Thank you, Carrie, and good morning, everyone. We reported a net loss of $3,600,000 or $06 per diluted share in the 2020, which included the impact of $3,600,000 in exploration expense related to the Etame seismic program during the quarter and $2,200,000 of expenses related to stock based compensation. As Carrie mentioned, the lifting scheduled for December 2020 was delayed to January 2021, which reduced sales volume by approximately a 155,000 barrels and revenues by approximately $7,800,000 while increasing inventory costs in the 2020. For comparison purposes, in the 2019, reported net income of $1,000,000 or $02 per diluted share, which included the impact from a noncash charge of $3,100,000 for unrealized mark to market losses related to our crude oil swaps, expense for stock based compensation of 700,000.0 and a $1,800,000 tax benefit related to a decrease in the valuation allowance on deferred tax assets. For the 2020, we reported net income of 7,600,000.0 and 13¢ per diluted share, which included an income tax benefit of 2,800,000.0, which reflected the impact of the decreased valuation allowances on deferred tax assets of 5,300,000.
Our adjusted net loss in the 2020 totaled 5,600,000.0 or 10¢ per diluted share as compared to adjusted net income of 5,500,000.0 or 9¢ per diluted share for the 2019. The decrease in earnings between years is mainly due to the lower revenues as a result of lower oil prices and lower sales due to the delay in the lifting scheduled for 2020, coupled with the $3,600,000 of seismic related to the exploration expenses in the 2020. In the 2020, VAPO reported $2,300,000 in adjusted net income or $04 per diluted share. Adjusted EBITDAX was $3,500,000 in the 2020 compared to $10,400,000 in the same period of 2019. In the 2020, adjusted EBITDAX was $7,000,000 As with the net loss and adjusted net loss, adjusted EBITDAX was impacted by the lower revenues.
Between the 2019 and the 2020, this was primarily a result of lower crude oil prices, whereas between the 2020 and the 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 forty six sixty two net barrels of oil per day increased 27% from thirty six sixty four in the 2019 due to the new wells which came online during 2020 from our successful 2019 and 2020 drilling program. Fourth quarter twenty twenty production was up 6% from the 2020, which has reduced due to the planned full field maintenance shutdown as well as OPEC plus curtailment. Sales volumes in the 2020 were down just 9% from the same period 2019 as the increase in sales from the new wells coming online in 2020 mitigated the impact of the delayed lifting. However, 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 2020, as Carrie 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 366% to $42.00 7 per barrel in the 2020 versus $65.80 per barrel in the same period in in 2019, but was down just 4% compared to $43.63 per barrel in the 2020. We didn't have any derivative contracts in place in the 2020. However, this past January, we did enter into new crude oil con crude oil commodity swap agreements for a total of 709,252 barrels at a dated Brent weighted average price of 53¢ per barrel for the period from and including February 2021 through January 2022. These swaps settle on a monthly basis.
As Carrie mentioned, we hedged a portion of our production volumes to protect cash flows, which will be used to fund our twenty twenty one, twenty twenty two drilling program. We took similar actions in 2019 before we began our twenty nineteen, twenty twenty program. But 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 risk and protect cash flow in the future as we consider any additional derivative contracts. Turning to expenses.
Production expense, excluding workovers, for the 2020 was 6,600,000.0 or $22.66 for a net barrel of oil sales. This is lower than the 9,800,000.0 in the 2019 and the 9,100,000.0 in the 2020, primarily due to the lower sales volumes in the 2020 resulting from the delayed lifting. The current unit production expense, including workovers of $22.66 per barrel in the 2020 decreased significantly as compared to the $30.70 per barrel in the 2019 due to the overall the higher overall production rate and was in line with the per unit production expense of $22.21 per barrel in the 2020. Included in total production expense are COVID-nineteen related costs incurred to protect the health and safety of the company's employees, which totaled approximately 400,000.0 in the 2020 and 1,600,000.0 for the full year of 2020. For the full year 2021, we are estimating the guidance range for our production expense, excluding workovers, to be between $69,000,000 and $77,000,000 or $24.5 to $29.25 per barrel of oil sales on a net revenue basis.
Production expense for the 2021 is projected to be between $16,500,000 and $18,500,000 or $26 to $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 02/25/2021. So for the 2021, we'll include approximately two months of financial results without staff of interest and one month with. Our production expense guidance excludes any potential future impact from COVID nineteen pandemic not currently being experienced. DD and A for the 2020 was 1,300,000.0 or $4.37 per net barrel of oil sales compared to 2,100,000.0 or $6.64 per net barrel in the 2019 and 2,200,000.0 or $5.37 per barrel in the 2020.
DD and A was lower than both prior periods due to lower sales volumes in the 2020 resulting from the delayed listing. The current unit DD and A rate in the 2020 was lower than the rate in the 2019 due to the impairment charge taken in the taken in the 2020. And the lower than the and lower than the rate in the 2020 due to higher production volumes in fields with a smaller, depreciable base. General and administrative expense for the 2020, excluding stock based compensation expense, was 2,500,000.0 compared with 2,200,000.0 in the same period of 2019 and 2,400,000.0 in the 2020. G and A expense was higher than in the same period of 2019 due to higher professional fees and legal costs and was similar to G and A expense in the 2020.
The current unit G and A rate in the 2020 of $8.73 per barrel of oil sales was higher in both the 2019 and 2020 due to the lower sales volumes as a result of the delayed lifting. For the full year 2020, we are forecasting G and A to be between 10,000,000 and $12,000,000 essentially unchanged from 2020 despite the large increase in production from the Sappho acquisition. While our total G and A expense isn't materially different in 2021, our G and 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 2,200,000.0 during the three months ended December '20, 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 full quarter of 2020, stock based expense related SARS was an expense of 1,900,000.0 compared to an expense of 600,000.0 in the 2019.
In the 2020, a benefit of 600,000.0 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 2020. The three months ended 12/31/2020, income tax was a benefit of 800,000.0 and included a deferred tax benefit of 2,800,000.0. For the three months ended 09/30/2020, income tax was a benefit of 2,800,000.0, included a 5,300,000.0 deferred tax benefit related to a decrease in valuation allowances on US and Gavanese deferred tax assets.
Income tax expense for the 2019 was 4,200,000.0, which included 1,800,000.0 of deferred tax expense rather than a benefit. Foreign income taxes are attributable to and and are settled by the government by taking their oil their crude oil in time. As detailed on Slide 28 in the presentation deck posted this morning on our website, we currently estimate that VAALCO's operational breakeven price 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 exclude 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 $14,000,000 This clearly shows our strong leverage to higher oil prices. At year end 2020, we had an unrestricted cash balance of $47,900,000 which includes $1,400,000 of net joint venture owner advances. Working capital at 12/31/2020, was $11,400,000 compared with 16,600,000.0 at at 09/30/2020, while adjusted working capital at 12/31/2020 totaled 24,300,000.0 compared with $29,300,000 at 09/30/2020.
For the full year 2020, net capital expenditures totaled $28,000,000 on a cash basis and 10,500,000 on an accrual basis. Our capital expenditures primarily related to the twenty nineteen, twenty twenty drilling program at Etame. It has it has been the case since the 2018, we are carrying no debt. With this, I will turn the call back over to Carey.
Speaker 2
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 three d seismic and will incorporate it with our twenty year our twenty plus years of knowledge as operator at Etom. The new seismic will help us to optimize and derisk future drilling locations and potentially identify new ones.
Now 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 02/2002, our third party reserve auditors estimated there was 30,000,000 barrels of gross recoverable oil. Over the years, we have drilled and expanded Etame such that we have produced over 120,000,000 gross barrels of oil thus far. Looking to the future, we believe that the field still has over 100,000,000 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. And with that, operator, we are ready to take questions.
Speaker 0
Thank you. We will now begin the question and answer session. Today's first question comes from Sefei Foucaud with Octus Advisories. Please go ahead.
Speaker 4
Hi, guys. Two questions for me, a bit detailed. The first one is around the 2C contingent resources. And particularly, I saw that the extension base on economics sort of move from 30,000,000 barrels to 18,000,000 barrels. 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 have jumped up so much. And the second one is very it's a simple one. It's just I saw that there is an increase in the payables, I think something that you called the account with JV partners. I think it's EUR 5,000,000. And I was wondering how the cash CapEx or would move in Q1 and if whether it would be we need to incorporate this €5,000,000 payment on top of the 2,000,000 to €3,000,000 I think that you have forecasted in CapEx for Q1.
Speaker 2
Okay, Stephane. Great to hear from you. I will will answer your first question. And then your second question, I'll I'll I'll revert over to Liz. But your first question on contingent resources related to license extension beyond 2028 and the change from 30,000,000 barrels to 18,000,000 barrels of contingent resources, what happened is those that 30,000,000 barrels was actually split into a combination of contingent and prospective resources.
And so you'll see that that there's another I'm sorry. I'm sorry. That's that's not correct. I'm sorry. The we have a management estimate of of perspective resources that we haven't included on the table.
But those contingent resources that you see for the extension, based on economics, those are Netherlands full numbers. As we 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 our internal estimates and work with, Netherlands who will next year to bring those those volumes back into, contingent. But, again, those are those are barrels that would have been produced from 2028 to 02/1938. And in in our view, they're they're perspective, and we will we will revisit those reserves as we, continue to evaluate our size mix. Now on your second question
Speaker 3
Yeah. So on, on the second question, the joint venture payables and receivables are really a function of when they're paying their cash cost. So we actually had a receivable as well that was fairly large at year end. And so the net of those two was a $1,400,000 payable. And so, yes, those do even out over time.
So 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. But over time, it does, you know, tend towards zero. So So I would say at year end, I mean, $1,400,000 that's not this is a pretty small amount of impact on cash flow in the future.
Speaker 0
Our next question today comes from Michael Santavao with Ankoria.
Speaker 5
I have a couple of questions. One on costs. And 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, and now it's gone to 26. So just curious. I know you went over a bunch of numbers down the on on the cost side, and I I couldn't really kinda cycle them.
But but we'd love to know what the the reason for the for the $5 increase from your December numbers to the deck you put out today, which include this one, I believe, includes the the Sesol acquisition.
Speaker 3
Yes. That's that's correct. Really, what's driving most of that increase is the lower production volumes. So about 90% of our OpEx is fixed. And so when the production volumes go down, the per barrel amount is going to go up and vice versa.
And so we saw a really nice decline in 2020 due to the drilling program. Well, we we have natural decline from the field. And so this year, because, you know, we're not doing another program, and we won't be bringing on new production and, you know, until very late in the year, maybe in the following year, you don't see the benefit. You know, that that per barrel amount is gonna go up. Now on an absolute basis, our our production expense is expected to be comparable between the two years.
And I think the midpoint of our guidance would would point you to that. What we tried the the other I mean, part of this is challenging because you've got the mixture of a portion of the year being with and without Sasol. So what we did in the press releases, we gave the gross numbers between the two years, and we discussed those. And and you'll see that the the midpoint of the guidance is close to what the gross number was last year.
Speaker 5
Okay. The if your decline rate is 15%, the the it would the 21 to '26 is a lot more than a 15% increase on a per barrel basis. Is there something else going on in there? Is there cost inflation? It's about
Speaker 3
about $4 of the decrease of the increase is is the production rate. There is a little bit of increase, you know, overall in production expense, but not, not a significant amount. The other thing that you need to take into consideration is the prices that we're using here. So you can there is a bit of a change you know, at the at slightly higher oil prices, you can end up with with slightly higher production expense as well because there is a a you know, there's 10% of it that is that is variable.
Speaker 5
Okay. And the other pieces of the puzzle have also gone up. The the tax has gone up at at $55 from December to to to today's deck a little by a little bit. And then the the g and a have gone up as well, and workovers has gone up. Everything seems to have gone up.
Is there is there is there a reason for for that?
Speaker 3
Well, on the on the if you're talking about on a per barrel basis, the the tax is gonna be a function of our revenues. So in general, and and this isn't a 100%, but in general, the the cash tax that we pay is gonna run about 10% of our revenue number. And the reason for that is that we're getting 80%. It's it's deductible. It's cost recovery.
So that leaves you at 20%, and we pay about 50% of that is is paid as a tax roughly. So when you're looking at a $65 oil price, I mean, you're gonna end up with a higher tax number per barrel to that because you got a higher oil price. In terms of the G and A, it's actually down on a per barrel basis from last year. So last year, I think we had $6.57 per barrel of G and A cost. And here, we're forecasting about $4 per barrel of G and A cost.
And that The
Speaker 5
the December the December deck showed $3.44 after the like, pre and post before acquisition after acquisition. It showed $3.44 after the acquisition. And then today, it's $4. So that was a that's a pretty significant percentage increase in the in that in that slice of the pie.
Speaker 3
Yeah. And that's gonna be more a function of of of the of the lower volumes in 2021.
Speaker 5
Okay. Let me ask my next question if I can. Where do you think the stack looks after your twenty twenty one, twenty twenty two drilling program? And where does your breakeven free cash flow go from and to?
Speaker 3
We haven't given any guidance on that. But one thing I can tell you is so for example, last drilling program, we if you there's a slide that shows the uplift. And and that was about 6,900 barrels a day gross. Okay? And Gary mentioned in his comments, and 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 7,008 barrels a day gross.
So you can kind of use that as a guide to to to help you understand, okay, what would 2022 look like, you know, with those additional barrels? I mean, obviously, it's gonna have, you know, a significant impact comparable to to what we saw in the 2020 the 2019, 2020 drilling program. But we haven't given I mean, we haven't given any guidance for for 2022 yet, but that that should help you at least directionally understand where where the per barrel costs are going.
Speaker 5
Okay. And then 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 2122 that starts later this year. Well, you're gonna do you have enough cash? I guess, between cash on hand and cash being generated, it looks like you're gonna be okay, or or do you plan on tapping a bank?
Speaker 2
No. Based on current oil pricing, we expect to fund the, the next drilling campaign from cash on hand.
Speaker 5
Okay. And and the hedging will protect some of that as well, you're saying?
Speaker 2
Yes. And that is exactly why we put the hedging in place. Correct.
Speaker 5
Are you layering more in in more hedges as we speak kind of thing, or or are we gonna Not not as we speak.
Speaker 2
I'm sorry. I interrupted you. We're we're not layering any hedges. Not not right now. Layering on any new hedges.
Not right now. But we are always considering new hedges.
Speaker 5
Okay. Alright. Great. Thanks. I'll yield the floor.
Speaker 2
Thank you. Thank you.
Speaker 0
Our next question comes from Bill Dezellem with Tieton Capital. Please go ahead.
Speaker 6
Thank you. A couple of questions. First of all, can you discuss the December lifting and why it was delayed to January? And then secondarily, because oil prices did go up in January versus December, how much was the benefit to you?
Speaker 2
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 nineteen 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. But, with all of our precautions that we have in place, it was more important to keep our our employees safe and healthy, and we decided to pause and and delay the lifting until we were certain that the the that, again, that our employees were safe and healthy.
So that was that was initial delay. And then secondarily, there were some operational issues. We had a a crane that, was not working on a support vessel. Not a crane, but a winch. I'm sorry.
Winch that was not properly functioning on a support vessel that cost just a few days. But, the really, the delay from December to January was primarily the, COVID nineteen protocols and our our commitment to keep our employees safe.
Speaker 6
And the Yeah. Benefit?
Speaker 2
And the benefit was $5 a barrel.
Speaker 3
That's right. So you had so the average price, if we had done it in December, the average would have been around $50, and that's that's kind of what we indicated with the 7,800,000.0 and a 155,000 barrel. And January prices ended up being around $55. So I mean, roughly, you know, that's 700 to 800,000 benefit for us.
Speaker 6
Excellent. Congratulations, I guess, on, not having the positive COVID and, and an extra 3 quarters of a million in your pocket.
Speaker 2
Yeah. Alright. Thank you, Bill.
Speaker 6
Next
Speaker 0
I apologize, mister Dezellem. Please rejoin the queue. In the meantime, our next question today is from Charlie Sharp with Canaccord. Please go ahead.
Speaker 5
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. And then 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.
Speaker 3
Okay. On the on the drilling campaign, at at the current oil prices that we see, I mean, we should be able to fund that easily with with cash on hand and cash flow being generated between now and and the time of the program. So so I would you know, while we haven't disclosed kind of a breakeven oil price or anything like that, that's I mean, we are we are we're happy with the the current oil prices from a funding perspective. And then on the FPSO
Speaker 2
On FPSO, Charlie, good to hear from you. And so you're correct. Our FPSO contract is expiring next year in September. And so 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 Natipa FPSO. And so I will say that both of those options, require some upfront costs.
You know, of course, if we replace the FPSO, there's installation costs and things. And then if we keep the Natipa on station, there are life extension costs. And so we're 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. So there are upfront costs, but I I'll say that we do expect long term costs to be less whether, so, you know, there there again, in a nutshell, the there will be some upfront costs, but long term, we expect costs to be lower.
Speaker 5
That's great. Thank you.
Speaker 0
And our next question today is from Bill Dezellem with Tieton Capital. Please go ahead again, sir.
Speaker 6
Thank you. Circling back to the drilling program, want to make sure that we're getting this right, that if we look at your forecasted production for 2021 and the forecast 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?
Speaker 3
Yeah. I think mechanically, that's correct. However, the the seven to 8,000 is the production rate at the end of the, you know, at the end of the program. So you're gonna have to, mean, I you're gonna have to look at 2022 on a full year basis. But you know, because you're you know, obviously, you're not gonna get the production that production for the entire year.
You're you may get it at the end of the program. And one of the reasons I mean, we didn't give we didn't try to get 2022 production because at this point, we don't have we're forecasting we're gonna start the program in in December, you know, late in in 2021, but there could be some things that could shift that forward or shift it back depending on the rig contract that we enter into and and So at this point, we we really it would be very difficult to give you kind of full year production rates for 2022.
Speaker 6
Oh, understood. But mechanically, other than that, if 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. And then the 'twenty two production relative to 'twenty one will simply be a function of the timing of when that program comes into play and natural decline rates.
Speaker 3
Exactly. Don't forget the natural decline because that's I mean, the existing wells will continue to decline over time in 'twenty six.
Speaker 6
That's very helpful. And 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 isn't really a big production benefit.
Speaker 3
Yeah. There is a on slide 10 in the deck, that kind of gives you a good view that we for 2019, we had, on a gross basis, 12,800 barrels a day. The uplift was 6,900, roughly. We ended up with 1,800 that was a decline. So 1,800 is is not quite 15%, but it's a little bit less than that.
And then and then we ended up you know, the overall average for the year was was was just below 18,000 a year a day. Thank
Speaker 6
you. I I had not seen that slide. So just again, I I did the math quickly. This is a the prior program was slightly less, meaning that this new program is slightly more in terms of that mechanical calculation.
Speaker 3
Yes.
Speaker 6
Excellent. And so then 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?
Speaker 2
Well, you know, we are, of course, looking into the design of a replacement vessel, and we would maximize the the the production capacity. There's there's other alternatives as well. But, yes, it is under con you know, the capacity of the the production capacity of the FPSO is definitely under consideration. And not only the production capacity, but the storage capacity. You know, we want plenty of storage if we're producing at high rates.
And so you're right, Bill. All of those are under consideration right now and part of the analysis that's ongoing.
Speaker 0
And our next question today comes from Garrett King with Shuffle Home Capital. Congratulations
Speaker 7
on the quarter and again on the deal, which looks like it was just an outstanding acquisition for you guys.
Speaker 2
Thank you, Garrett.
Speaker 7
So one one question I had is the 10 k states the cost recovery account is at 51,000,000. Should we expect that to increase in conjunction with the closing of the Sasol deal?
Speaker 3
We would acquire, you know, Sasol share of that. Now this is subject to certain adjustments and things, so we don't have the precise number, but there should be an increase yet.
Speaker 7
And should it be, like, in the ballpark of, you know, 80%? Or
Speaker 3
There's a lot there's a lot of factors that go into it, candidly. I mean, there's limitations on depending on what you pay for it and and the value at the time, and I I I will keep it in mind that that's of interest to people so that when we when we make our disclosures in the first quarter, we can we can consider adding that. But, I mean, it it should go up, but I I can't comment on whether it's gonna be an 80% increase or not.
Speaker 7
Understood. Okay. And for the FPSO, in the 10 k, it states that it could process approximately 25,000 to 30,000 barrels of fluids per day. And so is the right way to think about it that the capacity for this vessel is 25,000 to 30,000 gross barrels of production per day?
Speaker 2
Right. Right. The way to think about it is it's the capacity is 25,000 barrels of oil per day, plus we could send through another 5,000 barrels of water per day. So it's 25,000 barrels of oil per day or 30,000 barrels of a combination of oil and water. But keep in mind that we have processing capacity on all four of our platforms.
We removed the majority of the water on our platforms. And so, the way to think about it is there's 25,000 barrels of oil per day production capacity on the FPSO.
Speaker 7
Understood. Okay. And gross, Etame has been running I mean, in in your slide, you have it kind of peaking out in the 2020 at around 20,000 and then going up to maybe 22,000 and later in 2022. So it still seems like there is excess capacity on the vessel, which is provides a lot of leverage for you guys to the extent that you can increase production and fill it. Or potentially, if you feel like that's not realistic, getting a smaller vessel when the lease expires.
Is that kind of how you're thinking about it?
Speaker 2
Well, the the way we're thinking about it is you're right. We've managed over the past twenty years to to drill and produce the field at 15 to 20 or, between 15,025 barrels a day, trying to utilize the full capacity. Now going forward, like you mentioned, September year, we will either replace or, extend the Natipa. And our ambition is to increase capacity next September. And so that that's our ambition, but it has to come at the right price.
And so we have to look at, you know, what is the cost of increasing the capacity versus the the the possibilities that we have to fill that capacity. So all of that is under consideration, but I would say we would lean towards increasing the capacity, as of next
Speaker 5
Okay.
Speaker 7
And is this I mean, it sounds like you you said that you thought the total cost could 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?
Speaker 2
Well, I I you know, the overall market is not as active as it was twenty years ago when we installed the FPSO. And then again, I I think it was 2012 when we amended the contract. And so, you know, what we're what we're looking at again is we will have some upfront costs. But in this current market, we think we see the opportunity to reduce costs long term.
Speaker 7
Understood. And, yeah, just looking at your slide, on the deal, you guys paid 44,000,000. 4,000,000 of that was a deposit, and then that that was the agreed price. And then the cash that you're paying is gonna be 30. So the way I look at that is that this generated, $10,000,000 in cash in an eight month period at $49 Brent, and so that's three times the cash you're paying.
And then, obviously, it's a lot higher now. So that just seems like an incredible deal.
Speaker 3
Yeah. I think the other thing to keep in mind is that is during that time period, we had the five point program. And so and so that 10,000,000 was burdened by a quarter of seismic. So it's actually you know, if you excluded the seismic, you know, you get and you were looking more at a pure you know, more purely at at operating cost ongoing operating cost, the the number would have been higher.
Speaker 7
Wow. Okay. Alright. Well, I mean, that's just a great deal, and it's wonderful deal for shareholders. So we commend you guys.
Thank you.
Speaker 2
Thank you. We appreciate the feedback.
Speaker 0
And our next question today is a follow-up from Stephane Foucaud with Octus Advisories. Please go
Speaker 4
Yes. Hi again, guys. Two further questions for me. Can you say anything more on the plan for Block P? So the Memorandum of Understanding for the farm out has expired, but that still remain very interesting assets.
Oil price is much higher, which probably means that even smaller resources are probably more commercial than they look just six months ago. So how are you seeing the sequence of events for the block and what are your thought process? And secondly, another simple one. I was again looking at the hedging program, the $53 a barrel, that's fixed price or that's floor? If you can please remind me.
Thank you.
Speaker 2
Okay, Stephane. Thanks for the on Block p. You're correct. The, memorandum of understanding we have with Levine has expired, and that was an agreement for Levine to come in and carry us on the cost of an exploration well. And so those those discussions are still underway with Levine.
But since the the MOU has expired, we've broadened the discussions with other companies. And so, you know, there's there's a couple of different outcomes. And so we're one outcome that we're still pursuing is to find a partner to carry us on an exploration well. We're certainly certainly still pursuing that option. And then you're you're correct at these higher oil prices.
Another option that we have under evaluation is executing a standalone development of Venus discovery on Block P. And so right now, we're evaluating both of those options. We haven't committed to either one yet, but they're both very robust options. And like I've said in my earlier comments, the Venus discovery on Block P is 16,000,000 barrels of gross resources. And we're looking at, 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.
So that that is the, state of play for Block P in Equatorial Guinea. And if you don't mind, Stephane, could you repeat your second question for us?
Speaker 4
That was around, the aging program, and it's it's a detailed question whether the if you could remind me whether the $50 ish per barrel is a fixed price or whether it's just a floor so that you can still benefit from the upside and the current oil price for the volume that I did.
Speaker 3
The it's a it's a swap. So it's a fixed price of $53.10.
Speaker 4
Okay. Thank you. And and back of back on block p. So Carrie, do is your feeling that Levine is still a serious counterparty? And if it is not, do you get any sort of expression of interest from alternate parties?
Or is there the risk might start again from scratch on the exploration from out?
Speaker 2
On the on the exploration side, I can't really comment on, you know, the interest in other parties. Those, you know, we're still we're still negotiating and talking to other parties. So I I really at this stage, I can't comment on the level of interest. I I would say that, you know, Levine, I can't speak for what's happening internally with, with Levine and their management and their strategy, but I I can say that they chose not to extend extend the memorandum of understand or memorandum MOU that we had with them, you know, to get to an agreement or to re to help us reach a a farm out agreement. So, you know, clearly, their their level of interest changed.
They have not extended the MOU, but we are still in discussions with Laveen.
Speaker 5
And
Speaker 0
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.
Speaker 2
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.
Speaker 0
Thank you, sir. This concludes today's conference call. You may all disconnect your lines, and have a wonderful
Speaker 3
day.