VAALCO Energy Inc (EGY) 2020 Q4 法說會逐字稿

Good day, and welcome to the VAALCO Energy Fourth Quarter and Full Year 2020 Earnings Conference Call.

(Operator Instructions) 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.

(Operator Instructions)

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 filed 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, and 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 out all our outstanding debt and begin 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 3 successful development wells and 2 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-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 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 2021.

We are planning to drill up to 4 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 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 rent oil prices averaged greater than $60 per barrel for 90 consecutive days.

We closed the acquisition on February 25 of this year, taking into account the $4.3 million deposit and then 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 average 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 2 months of VAALCO volumes and 1 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 7-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 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 $3.5 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 with priced at January rep pricing, which was higher than December.

For the full year 2020, we generated $26.6 million in adjusted EBITDAX.

Now I would like to discuss the progress of our 3-D seismic acquisition and our plans for the next drilling campaign is 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-driven 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 4 wells starting in the fourth quarter of 2021 and finishing in 2022.

We are currently expecting to drill 2 development wells and 2 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 4-well program is successful, the estimated increase in gross field production is 7,000 to 8,000 barrels of oil per day, or 3,500 to 4,100 net barrels of oil per day to VAALCO, where the driven campaign is completed in 2022.

The estimated cost of the program is between $115 million and $125 million gross, or $73 million to $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 to $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.

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 1.6 million barrels as a result of positive performance revisions and the discovery of Southeast Etame 4P, reserves were slightly down year-over-year.

The downward revisions were driven by 1.88 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 in 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 remains 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 of 2020 was $84.4 million, assuming year-end 2020 escalated rent 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 their 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 approved 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 rent 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 and 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 nonbinding 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 with our increase -- 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, and 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 listing scheduled for December 2020 was delayed to January 2021, which reduced sales volumes by approximately 155,000 barrels and revenue by approximately $7.8 million, while increasing inventory costs in the fourth quarter of 2020.

For comparison purposes, in the fourth quarter of 2019 recorded net income of $1 million, or $0.02 per diluted share, which included the impact from a noncash charge of $3.1 million for unrealized mark-to-market losses related to our crude oil swaps, 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, or $0.13 per diluted share, which included an income tax benefit of $2.8 million, which reflected the impact of the decrease in 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 is mainly due to the lower revenues as a result of lower oil prices and lower sales due to the delay in the listing scheduled 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 EBITDAX 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 EBITDAX was $7 million, as with the net loss and adjusted net loss, adjusted EBITDAX was impacted by the lower revenue 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 listing scheduled for this past December.

Production for the fourth quarter of 4,662 net barrels of oil per day increased 27% from 3,664 in the fourth quarter of 2019 due to the new wells that came online during in 2020 from our successful 2019/2020 drilling program.

Fourth quarter of 2020 production was up 6% from the third quarter of 2020, which has reduced due to the planned full field maintenance shut meal as well as OPEC+ curtailment.

Sales volumes in the fourth quarter of 2020 were down just 9% from the same period of 2019 as the increase in sales from the new wells coming online in 2020 mitigated the impact of the delayed listing.

However, the impact of the delayed listing was a 30% decrease in revenues between the third and fourth quarter.

While the delight listing reduced revenues for the fourth quarter 2020, as Cary mentioned, pricing improved somewhat between December 2020 and January 2021, thereby increasing the amount ultimately realized from the listed.

Our crude oil price realizations fell 36% to 4,207 per barrel in the fourth quarter of 2020 versus 6,580 per barrel in the same period in 2019 but was down just 4% compared to 4,363 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 barrels at a dated weighted average $53.10 per barrel for the period from and including February 2021 through January 2022.

These swaps fell 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 2021/2020 catering program.

We took similar actions in 2019 before we began our 2019/2020 program.

These hedges were particularly beneficial for us in 2020, the crude oil prices fell and we were ramping 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 and additional derivative contracts.

Current expenses, production expense, excluding workovers for the fourth quarter of 2020 was $6.6 million, or 2,666 per net barrel of oil sales, which is 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 for the fourth quarter of 2020, resulting from the delayed listing.

The current unit production expense, excluding workovers of $22.66 per barrel in the fourth quarter of 2020, decreased significantly as compared to the $30.70 per barrel in the fourth quarter of 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 third quarter of 2020.

Included in total production expense or COVID-19 related costs encouraged 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 to $29.25 per barrel of oil sold 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 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, February 23, 2021.

So for the first quarter of 2021, will include approximately 2 months of financial results without Sasol interest and 1 month with.

Our production expense guidance excludes any potential future impact 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 period due to lower sales volumes in the fourth quarter of 2020, resulting from the delayed listing.

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 the lower than -- and lower than the rate in the third quarter of 2020 due to higher production volumes to feel 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 of 2019 due to higher professional fees.

And local costs and was similar to G&A expense in the third quarter of 2020.

The prior G&A rate in the fourth quarter of 2020 of $8.73 per barrel of oil sales was higher compared to the fourth quarter of 2019 and third quarter 2020 due to the lower sales volumes as a result of the delayed listing.

For the full year 2020, we are forecasting G&A between $10 million and $12 million eventually unchanged from 2020 despite the large increase in production with the Sasol acquisition.

While our total G&A expense, this is 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 3 months ended December 31, 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 full 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.

For 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.

Coming now to taxes.

Income tax was a benefit for both the fourth and third quarters of 2020.

For the 3 months ended December 31, 2020, income tax was a benefit of $0.8 million and included a deferred tax benefit of $2.8 million.

For the 3 months ended September 30, 2020, income tax was a benefit of $2.8 million, included a $5.3 million deferred tax benefit related to decreased valuation allowances on U.S. and Gabon's before tax assets.

Income tax expense for the fourth quarter of 2019 was $4.2 million, which included $1.8 million of deferred tax expense for other than the benefit.

Forward income taxes are attributable to go on and are settled by the government by taking their oil, their crude oil in Etame.

As detailed on Slide 28 in the presentation deck posted this morning on our website, we currently estimate that VAALCO's operational breakeven price to 2021 is now approximately $32.25 per net barrel of oil sales, and our free cash flow breakeven price was approximately $38.75 per net barrel of oil sales.

Keep in mind that our realized prices of benchmark to crude oil prices.

These breakeven prices increased over 2020, primarily as a result of lower production rates, reflecting natural declines.

In addition, we have 2 workovers planned as compared to one in 2020.

These estimates included the impact -- excluded the impact of our hedges.

In general terms, we estimate that each $5 increase in realized oil prices, increases our annual adjusted EBITDAX by approximately $14 million.

This clearly shows our strong leverage to higher oil pricing.

At year-end 2020, we had an unrestricted cash balance of $47.9 million, which includes $1.4 million of net joint venture under advances.

Working capital at December 31, 2020, was $11.4 million compared with $16.6 million at September 30, 2020.

While adjusted working capital at December 31, 2020, totaled $24.3 million compared with $29.3 million at September 30, 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 in Etame.

It has been the case since the second quarter of 2018, we are carrying net 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 believe 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-year -- our 20-plus 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.

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 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 are planning to drill up to 4 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 the 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 3 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.

(Operator Instructions) Today's first question comes from Stephane Foucaud with Auctus Advisors.

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 million barrel to 18 million barrel.

Given those are quite some low-risk resources is 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 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, is $5 million.

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 million payment on top of the $2 million to $3 million, I think, that you have forecasted in CapEx for Q1.

Okay.

Stephane, I will answer your first question.

And then your second question, I'll revert over to Liz.

But to 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 those -- that 30 million barrels was actually split into a combination of contingent and prospective resources.

And so you'll see that there's another -- I'm sorry, I'm sorry, that's not correct.

I'm sorry.

The -- 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.

But again, those are barrels that would have been produced from 2028 to 2038 at and in our view, their perspective, and we will revisit those reserves as we continue to evacuate our seismic.

Now on your second question.

Yes, Stephane, on the second question, the joint venture, payables and receivables are really a function of when they're paying their cash calls.

So we actually had a receivable as well that was fairly large at year-end.

And so the net of those 2 was a $1.4 million payable.

And so yes, those -- they 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 0. Well, it never is because you're never perfected forecasting that stuff.

But over time, it does tend towards 0. So I would say, at year-end, I mean, the $1.4 million, that's not -- this is a pretty small amount of impact on cash flow in the future.

Our next question today comes from Michael Santelli with Ancora.

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 8 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 on the cost side, and I couldn't really kind of cipher them.

But I'd love to know what the reason for the $5 increase from your December numbers to the deck you put out today, which include this one, I believe, includes the Sasol acquisition.

Yes.

That's correct.

So really what's driving most of that increase is the lower production volume.

So about 90% of our OpEx is fixed.

And so when the production volumes go down, the per barrel amount is going to go in vice versa.

And so we saw a really nice decline in 2020 due to the drilling program.

Well, we had a natural decline from the field.

And so 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 will 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 2 years.

And I think the midpoint of our guidance would point you to that.

What we try to -- 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 growth numbers between the 2 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.

The -- your decline rate, 15%, the 21% to 26% is a lot more than a 15% increase on a per barrel basis.

Is there something else going on there?

Is there cost inflation in there as well?

About $4 of the decrease -- 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.

So you can -- 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 is -- there's 10% of it that is variable.

Okay.

And the other pieces of the puzzle have also gone up, the tax has gone up at $65 from December to today's deck a little bit.

And then the G&A has gone up as well and workovers has gone up.

Everything has gone up.

Is there a reason for that?

(inaudible)

Well, on the -- if you're talking about on a per barrel basis, the tax is going to be a function of our revenues.

So 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.

And the reason for that is that we're getting 80% is deductible as cost recovery.

So that ratio is 20%, and we pay about -- 50% of that is paid as a tax, roughly.

So when you're looking at a $65 oil price, I mean, you're going to end up with a higher tax number per barrel just to back roll 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.

So last year, I think we had $6.57 per barrel of G&A costs.

And here, we're forecasting about $4 per barrel at G&A cost and that (inaudible)

The December deck showed $3.44 after the -- look, pre and post before acquisition after acquisition and sort of $3.44 after the acquisition.

And then today, it's $4.

So that's a pretty significant percentage increase in that next slice of the pie.

Yes.

And that's going to be more a function at 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, '22 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, we -- there's a slide that shows the uplift, and that was about 6,900 barrels a day gross, okay?

And as 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 is completed at somewhere between 7,000 and 8,000 barrels a day gross.

So you can kind of use that as a guide to help you understand, okay, what will 2022 look like with those additional barrels.

I mean, obviously, it's going to have a significant impact comparable to what we saw in 2020 -- the 2019/2020 drilling program.

But we haven't given -- I mean, we haven't given any guidance for 2022 yet, but that should help you at least directionally understand where the per barrel costs are going.

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, '21, '22 that starts later this year.

Well, 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 taping a bank?

No.

Based on the current oil pricing, we expect to fund the next drilling campaign from cash on hand.

Okay.

And the hedging will protect some of that as well, you're saying.

Yes.

And that is exactly why we put the hedging in place, correct.

Are you layering in more hedging as we speak, something, or you are going to (inaudible)

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.

Our next question comes from Bill Dezellem with Tieton Capital.

A couple of questions.

First of all, can you discuss the December listing, 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?

Sure.

Bill, thanks for the questions.

Okay, the delay in the listing or the delay in the December so as 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 listing 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 employees safe and healthy, and we decided to pause and delay the lifting until we were certain that, again, that our employees were safe and healthy.

So that was the initial delay.

And then secondarily, there were some operational issues.

We had a crane that was not working on the support vessel -- not a crane but a winch, I'm sorry, winch that was not properly functioning on a support vessel that cost us a few days.

But really, the delay from December to January was primarily the COVID-19 protocols and our commitment to keep our employees safe.

And the benefit?

And the benefit was $5 a barrel.

That's right.

So you had -- so the average price, if we evented in December, the average would have been around $50, and that's kind of what we indicated with the $7.8 million and the 155,000 barrels, and January prices ended up being around $55.

So I mean roughly that's 7,000 to 8,000 benefit for us.

Excellent.

Congratulations, I guess, on not having the positive COVID and an extra $0.75 million in your pocket.

Yeah.

All right.

Thank you, Bill.

Our next question today is from Charlie Sharp Canaccord.

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?

Okay.

On the drilling campaign, at the current oil prices that we see, I mean, we should be able to fund that easily with cash on hand and cash flow be generated between now and the time of the program.

So while we haven't disclosed kind of a breakeven oil price or anything like that, that I mean we are -- we're happy with the current oil prices from a spending perspective.

And then on the FPSO...

On the 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, I'd like to mention, replacing the FPSO or extending the life of the existing FPSO, which is the Nautipa FPSO.

And so 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 our people on station, there are life extension costs.

And so 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 will take, we will disclose those upfront costs.

So there are upfront costs, but I'll say that we do expect long-term cost to be less, whether -- so they're -- again, in a nutshell, there will be some upfront costs, but long term, we expect costs to be lower.

And our next question today is from Bill Dezellem some with Tieton Capital.

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 and the -- 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?

Yes.

I think mechanically, that's correct.

However, the 7,000 to 8,000 is the production rate up again to the program.

So if you're going to -- I mean, you're going to have to look at 2022 on a full year basis.

But because you're -- obviously, you're not going to get the production -- that production for the entire year, 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 going to start the program in December, late in 2021, but 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.

So at this point, we really -- it will be very difficult to give you kind of full year production rates for 2022.

Understood.

But 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.

And then the '22 production relative to '21 will simply be a function of the timing of when that program comes into play and natural decline rates.

Exactly.

Yes.

Yes.

Don't forget the natural decline because that's, I mean, the existing wells will continue to decline over time.

It's like to...

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 is really a big production benefit.

Yes, there's a Slide 10 in the deck, that kind of gives you a good view that we -- for 2019, we had, on a growth basis, 12,800 barrels a day.

The uplift was 6,900 roughly.

We ended up with 1,800 that was the decline.

So 1,800 is not quite 15%, but it's a little bit less than that.

And then we ended up the overall average for the year was on -- was just below 18,000 a year -- a day.

I had not seen that slide.

So just again, I did the math quickly.

This is -- the prior program was slightly less, meaning that this new program is slightly more in terms of that mechanical calculation.

Yes.

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?

Well, we are, of course, looking into the design of a replacement vessel and we would maximize the production capacity.

There's other alternatives as well.

But yes, it is under -- the capacity -- the production capacity of the FPSO is definitely under consideration.

And not only the production capacity, but the storage capacity.

We want plenty of storage if we're producing at high rates.

And so you're right, all of those are under consideration right now and part of the analysis that's ongoing.

Congratulations.

Okay.

Thank you, Bill.

Our next question today comes from Garrett King with Truffle Hound Capital.

Congratulations on the quarter, and again, on the deal, which looks like it was just an outstanding acquisition for you guys.

Thank you, Garrett.

So 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.

Now this is subject to certain adjustments to things.

So we don't have a precise number, but there should be an increase, yes.

And should it be like in the ballpark of 80%?

Or...

There's a lot of factors that go into it, candidly.

I mean this limitation is on, depending on what you pay for and the value at the time.

And I -- 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.

But I mean, it should go up, but I can't comment on whether it's going to be an 80% increase or not.

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, the capacity for this vessel is 25,000 to 30,000 gross barrels of production per day?

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 4 of our platforms.

We've 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.

Understood.

Okay.

And gross the -- Etame has been running, I mean, in your slide, you have it kind of peaking out in the early part of 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?

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 15 to 20 -- between 15,000 and 25,000 barrels a day, trying to utilize the full capacity.

Now going forward, like you mentioned, September of next year, we will either replace or extend the Nautipa.

And our ambition is to increase capacity next September.

And so that's our ambition, but it has to come at the right price.

And so we have to look at what is the cost of increasing the capacity versus 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 (inaudible)

Okay.

And is this -- I mean, 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.

And then again, I think it was 2012 when we amended the contract.

And so 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.

And just looking at your slide on the deal, you guys paid $44 million.

$4 million of that was a deposit and then that was the agreed price.

And then the cash that you're paying is going to be $30 million.

So the way I look at that is that is it has generated $10 million in cash in an 8-month period at $49 Brent.

And so that's 3x the cash you're paying.

And then obviously, it's a lot higher now.

So that just seems like an incredible deal.

Yes.

I think the other thing to keep in mind is during that contrary, we had a seismic program.

And so that $10 million was burdened by a quarter of seismic.

So it's actually -- if you excluded the seismic, you would -- and you're looking more at a pure -- more purely at operating cost, ongoing operating costs as the number would have been higher.

Wow.

Okay.

All right.

Well, I mean, that's just a great deal, and it's a wonderful deal for shareholders.

So we commend you guys.

Thank you.

We appreciate the feedback.

And our next question today is a follow-up from Stephane Foucaud with Auctus Advisors.

Two further questions for me.

Can you say anything more on the plan for a Block P?

So the memorandum of understanding for the farm-out has expired, but I 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 6 months ago.

So how are you seeing the sequence of event 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 a floor?

If you can please remind me.

Okay.

Stephane, thanks for the questions.

On Block P, you're correct.

The memorandum of understanding we have what Levene has expired, and that was an agreement for Levene to come in and carry us on the cost of an exploration well.

And so those discussions are still underway with Levene, but since the MOU has expired, we've broadened the discussions with other companies.

And so there's a couple of different outcomes.

And so there's 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.

And then you're correct at these higher oil prices, another option that we have under evaluation is executing a stand-alone development of the 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 of 16 million barrels of growth resources and 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 is the state of play for Block P and Equatorial Guinea.

And 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, whether the -- could you remind me whether the $50-ish per barrel is a fixed price or whether it's just a floor that you can still benefit from the upside and the current oil price for the volume (inaudible)?

The -- it's a swap.

So it's a fixed price at $53.10.

Okay.

And back on Block P. So Cary, do -- you're feeling that Levene is still a serious counterparty?

And if it is not, do you get any sort of expression of interest for multi-made parties?

Or is there the risk you might start again from scratch on the exploration format?

On the exploration side, I can't really comment on the interest in other parties.

Those -- we're still negotiating and talking to other parties.

I really -- 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, but I can say that they chose not to extend the memorandum of understand -- or memorandum, MOU, that we have with them to get to an agreement or to help us reach a farm-out agreement.

So clearly, their level of interest has changed.

They have not extended the MOU, but we are still in discussions with Levene.

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.