Panoro Energy ASA

Good morning, everyone. This is John Hamilton and welcome to our Trading and Financial Update for the First Quarter of 2021.

I’m joined today by my colleagues Richard Morton, our Technical Director; Nigel McKim, our Project Director; Qazi Qadeer, our CFO. I will take you through some slides following, which we’ll be open for some Q&A.

As a reminder today’s conference call contains certain statements that are may be deemed to be forward-looking statements, which include all statements other than statements of historical fact. Forward-looking statements involve making certain assumptions based on the company’s experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate to make under the circumstances.

Although we believe the expectations reflected in these forward-looking statements are reasonable, actual events or results may differ materially from those projected or implied in such forward-looking statements due to known or unknown risks, uncertainties and other factors. So the current slide you’re seeing is the way in which you can ask questions either during the slide presentation, in which case we’ll pick them up if you write them in, or you can raise your hand using the hand icon and we’ll try and take your verbal questions as well.

Next slide please. So a quick overview of the company.

We believe this is our most important quarter ever in the history of Panoro. We completed the acquisitions from Tullow, in Equatorial Guinea, and increasing our stake in Gabon that transaction should close soon in Gabon.

And what we have now is what we believe to be truly a full cycle E&P company. We have operations for the north of Africa right down to the tip.

In South Africa, we have production diversified across three different countries. We have a 2P and 2C resource number in excess of 70 million barrels.

We have a long reserve life on our assets and we hope to be producing somewhere in the range of around 9,000 barrels a day during the course of this year. So we believe through these transactions and over the past couple of years, we have built a very sustainable business in E&P in Africa.

I’m very proud of that. Next slide please.

So some of the key messages we want to get across in terms of the equity story here are three key messages. One is that we were in production growth mode.

We have organic production growth in our portfolio. We hope to be producing around 9,000 barrels a day.

This year on average, we’ve drilled five new production wells still this year, three in Equatorial Guinea and two in Gabon to be brought on stream. We hope to have an exit rate in excess of 9,500 barrels a day at the end of the year and we’re on target to produce in excess of 12,000 barrels a day during the course of 2023.

So, we have within the portfolio production growth. We also have near term triggers.

We have an exploration well in Gabon Hibiscus North, we have an exploration well in South Africa, which we hope to drill by the end of the year. And we also have the Petronor dividend, the dividend of Petronor shares, which we hope to complete that transaction in the near future.

And on a cash flow basis, we are sort of being judged now on a cash flow basis, we have very strong free cash flow in this business. We are fully financed for the growth that we have announced and we’re well-positioned to pay dividends in 2023.

These are the key messages we want to get across. Next slide, please.

So, on a pro forma basis or 2021 first quarter highlights we obviously announced the transformational acquisitions. Group net production was 8,000 barrels a day on a pro forma basis by pro forma we mean including the effect of the increased stake in Gabon and the new asset in Equatorial Guinea.

We have production growth activities across the portfolio, which I’ll touch on. We have big quarter in terms of liftings.

We have three crude liftings one in Tunisia, one in Gabon and a big one at EG, $59 million cargo in EG. And although it gets kind of repetitive to talk about these days, we still are working in a COVID environment.

And we are pleased to say that our systems, our health and safety record and our protocols improved again, resilience in the quarter On the financial side, you can see the effect on a pro forma basis of our revenue line and also our EBITDA which is $25 million that’s been reduced by $31 million simply on an accounting basis, given the over lift position in Equatorial Guinea when we lifted that cargo. Sudden unwind during the course of the year.

So, it’s hard to look at it on a quarterly basis because of that over lift, under lift, but it gives you a feeling on EBITDA side about the strength of this business now with very strong numbers coming through, which you’ll see again that overlooked position from an accounting perspective on one $31 million recovered back in through EBITDA. And again, we have a lot going on our balance sheet at the end of the quarter.

It’s kind of hard to describe it, because we have all the movements around the completion of the acquisitions, drawdowns of debts and all that. And we also have this huge receivable, $59 million from the cargo we lifted in EG.

We received the cash for that now in April. So the balance sheet is quite, quite different as well.

Next slide, please. Here are the financials and some more detail.

I won’t go into them in a huge level of detail here. But as you can see, what we’re doing is we’re reporting on IFRS reporting in one column showing the effect of the pro form of the acquisitions and on a pro forma basis, showing the financials, where again, you can see $77 million of pro forma revenue, with EBITDA of $25 million, recognizing the $31 million over lift that comes through.

So we’re in a very, very strong position financially. Next slide, please.

So what we’d like to do is take you through at a high level each of the assets we have now. Equatorial Guinea, we produced net 4,300 barrels a day.

On a gross basis, this is 30,000 barrels a day, which is exactly on target from what we anticipated. Equatorial Guinea now represents more than 50% of our production.

So this is now our most important asset by far in terms of production. And what’s quite exciting about Equatorial Guinea, we believe is that we’re really on the cusp of the operator finally drilling new wells and trying to boost production here.

So the past three years, the operator tried into bought this asset two years ago and they spent those three years upgrading the facilities, not drilled many new wells. And in fact, they’ve been known to drill wells drilled in Equatorial Guinea since 2015.

So the real task from when they bought the asset from HESS was to improve the infrastructure work on debottlenecking sort of if I can put it this way, kind of boring stuff, resting decline on the wells are looking to do things smarter and better. And so now is the harvest time.

And the first of those will be three wells to be drilled this year. The first we expect in June in the Elon field.

And again, these are the first wells to be drilled in since 2015. I mentioned the cargo that we’ve already lifted, which was brilliant.

We had a $59 million cargo one week after completing the transaction where we paid $88 million for this asset. So again, you can show at these oil prices, how cash generative this can be for Panoro.

The Okume upgrade project is nearing completion, there is additional power, water injection and gas lift capacity being installed. So again, things that are improving production and the operations we also have convinced the second phase of the ESP program there.

So we’re going to start seeing production growth in those assets during the course of this year. And perhaps just as importantly, the JV is very focused on production growth in 2022 and beyond.

So we’re really, again at the point here where the joint venture is not focused on boosting production having spent three years investing in this asset. Next slide, please.

In Gabon on a pro forma basis, we produced 2,380 barrels during the quarter. So that concludes the effect of the additional 10% from Tullow.

And really this was production from four wells. As those of you follow us will know we’re busy now drilling the Tortue production well, DTM-7, which the well is ongoing now.

And we plan to hook that well up and DTM-6H, which is the lower drilled right at the time of COVID really hit and bring those online during the end of the third quarter, probably at Tortue. So we should see production growth coming in towards the back end of the year in Gabon.

We did lift one lifting and that’s 56,000 barrels during the quarter that does not – that number does not include the factor of Tullow 10% that’s just a blip. And Hibiscus/Ruche development, first of all, it’s now targeted for the fourth quarter of 2022.

BW Energy, the operator announced their results last week and the good news here that we’ve moved up the first oil target from that development from the first quarter of 2023 now it’s fourth quarter of 2022. So there’s been some very good news, very good progress on that particular project, which we’ll see production get towards up – towards the FPSO capacity of 45,000 barrels a day or more.

We’re going to be drilling the Hibiscus North prospect in the third quarter. So we have another exploration trigger in there.

The Hibiscus Extension where we drilled in May did not encounter hydrocarbons. And lastly, we’re expecting the closing of the Tullow acquisition during the second quarter, so in other words, in next couple of weeks.

So we look to complete that one soon. Gabon now represents approximately 35% of our production.

Tunisia, next slide, please. Tunisia, we produce a little over 1,300 barrels a day net to Panoro, 4,500 barrels a day gross.

Production is frequently in excess of 5,000 barrels a day. So over a period of a quarter, you get certain shut-ins of wells or temporary shutdowns that might impact the average over a quarter, but it’s fair to say that production is frequently in excess of 5,000 barrels a day.

And I think it really demonstrates what we’ve done since we’ve taken over the asset, where we’ve managed to boost production by 30% or 40% from the time that we bought it from OMV. So again, we’re very, very happy with our Tunisian asset and the production growth we’ve managed to achieve.

We also had a lifting in the quarter for about 96,000 barrels at about $60 a barrel. And we continue with the production growth story in Tunisia with workovers planned at El Ain and Cercina are the ones that are right in front of us now.

So we hope to be able to continue the production growth story in Tunisia as we go. We’re also looking at the long-term potential of the asset working with ETAP, our partner to update the subsurface models and plan further developments in some of the fields, including most importantly, probably the Guebiba field, although this is true for all of the fields in Tunisia as well.

Next slide please. So in South Africa, we recently announced the completion of our transaction, we got the ministerial consent there, which is good.

It took a little while to come. The focus is now really on getting after the well and procuring a rig for the Gazania-1 well, which we hope to start by the end of the year.

This is a very significant prospects. It is an existing discovery.

The A-J1 discovery back in 1988 back in apartheid times. And what we’re trying to do here with this well is to come up with that and targeting two different geological prospects within this basins coming up from the discovery.

The success case has the potential to be in excess of 300 million barrels gross in terms of prospective resource. So it was very meaningful well.

And again, we hope to spot that well by the end of this year. So we have a very interesting exploration trigger later this year in South Africa.

Next slide please. So this is our guidance.

This is unchanged from what we provided at the time of our February Q4 our 2020 results. We haven’t changed anything here.

The production around 9,000 barrels a day, again benefiting from the fact that we have diversified production from three different assets here. We’ve not changed our production guidance.

And the capital expenditure side, we’ve not changed this number in particular Gabon is a little susceptible to exact timing differences because the Hibiscus/Ruche development is an 18-month project basically. So exactly when CapEx gets spent whether it’s a December 2021 or January 2022, you might find some differences in these numbers, but overall over the next couple of years, I think we provided good guidance on the CapEx on that, but we not amended our CapEx guidance on number of liftings.

We also not done that. We had three liftings in this quarter.

In the second quarter we will have two liftings in Gabon and one in Tunisia. And then the fourth quarter is when we probably have another EG lifting that’s probably a 650,000 barrel lifting probably in the fourth quarter as well.

So as you more one can see with our Equatorial Guinea lifting that we’ve just had, those are quite lumpy affairs when they come there the big numbers and when they fall exactly in the quarter, we recognize revenue at the time of lifting. So you could see on a quarterly basis, some quite some difference, but an important thing is to look out over a period of a financial year.

Next slide, please. So here’s a summary of the near-term triggers that we have and everything going on in the company again.

In Gabon, we’re drilling the DTM-7 well, looking up DTM-6 that all happened probably towards the end of the third quarter. We are drilling an exploration well Hibiscus North, we plan to drill wells every year in Gabon.

The Hibiscus North prospect is unaffected by what happened in the Hibiscus, it’s a very robust structure, and we’re looking forward to drilling that one. And Equatorial Guinea, as I mentioned, the first three infill wells being drilled this year, we will see this trend, we believe continuing to 2022.

Those additional wells in EG have not been sanctioned yet by the joint venture that typically happens in the third quarter, but we would fully expect to see a number of production wells being drilled every year in Equatorial Guinea trying to, again, increase production in there. In Tunisia, we continue with our well work-over activity.

So it could be see some news flow there coming through on the production side. With PetroNor dividend, which we intend to distribute to our shareholders upon completion of that transaction and we have an exploration well in South Africa, so we have a busy year ahead of us.

Next slide, please. And just a comment on where we are currently in terms of our market cap, which is obviously taken a bit of a hit on the Hibiscus Extension well, the strengthening of the north perhaps some other factors as well in there.

But our market cap has come down quite a bit from where it was prior to drilling that well, which surprising to us. What we’ve done here on this slide is to kind of just take some of the analysts’ projections, take an average of where we see the analysts are pointing and trying to compare that against our market cap.

And what you can see here is on an operating cash flow basis is $60 Brent will be generating for the next three years, $260 million according to the analysts assumptions like in an average of them and $450 million in operating cash flow over the next five years. We look at free cash flow, which the only difference between the two well is capital expenditure.

We’re obviously spending quite a bit of money in Gabon at the moment for the Hibiscus/Ruche development. So you’ll see over the next three years that we’ll be generating about $150 million in free cash.

And then if you look over the next five years considerably more. And when you compare that against our market cap, we would argue that this is quite a compelling valuation, sorry, I don’t think you’ll find many other companies with this kind of cash flow versus market cap dynamic.

The analysts are estimating free cash flow yields of between 20% and 40% over the next four years as we go forward. And again, the important part is, we have free cash flow really starts taking off in 2023, as we get through CapEx period in that Hibiscus/Ruche development.

So we’re going to come up very, very strong free cash flow generating company. And beyond the cash flow in that period, we obviously have – we’re planning to pay dividends.

We’re fully financed, we have observed life that is well in excess 10 years here, we’ve got 33 million barrels of 2C resources, which are not included in any of these assumptions. So we don’t include any contingent resource in our production assumptions and our cash flow assumptions.

Those are things that are not yet been sanctioned to be produced and most of those resigned with an Equatorial Guinea and we can come back to that perhaps in the Q&A. So there is inconsiderable upside here from these numbers.

And on top of that, we have other triggers every year. We have exploration wells each year.

We have a growth strategy to compliment the return of cash to shareholders. So we think we have quite a dynamic company that’s going to be a significant cash flow generator with many other triggers on it against the rather what we believe is a modest return market capitalization.

So with that, I’m finishing up and I will open up to questions. Qazi is going to chair the questioning.

So again, as a reminder, you can either raise your hand using the icon or you can type in a question to the question panel. We’re happy to take questions and my colleagues may join in some of those as well.

We have a question from Stephen Foucaud. I’m going to open the line.

Stephen, you may speak now, please.

Yes. Hi guys.

Good morning. Two questions for me.

First, an accounting one. The $67 million current payable, I assume that we first to be expected payments of Gabon in closing.

That’s my first question. My second question around Equatorial Guinea and I was wondering whether, one, the three ways that would drilled in 2021 that would have any impact on the reserve, particularly whether some of the 2C are being targeted.

And related to EG, how do you see the potential reserve – additional reserve booking moving forward with those 2C conversions? Is it fair?

Would you see a boarding where you would be starting sanctioning heftier drilling program that would suddenly boost the 2P reserve? Thank you.

Qazi, you want to take the first one on the payable position and then perhaps, Nigel, you can – Nigel and Richard can answer the EG one and particularly the conversion 2C to 2P reserves.

Yes, Hamilton, I will start with the payable position. The cash position Stephen is that consolidation of the Equatorial Guinea business, which was supposed to be at fair value as of the completion date of 31st March.

So as part of the acquisition, we have done two things. One is that we have acquired all assets and liabilities at fair value.

By fair value I mean, the act on over lift position was also fair valued as well. So we mentioned about the $31 million over lift position.

It was basically ends up in kind of upcoming launch table or trade table that we would see a jump in the tables, but we expect that to unwind as we produce more and replace in reserves. Few other things in terms of you are correct that I’d be able, we haven’t booked a couple of newspapers yet that would only happen on completion, but there are some items like difficult situation of $500 and some other payments in relation to the positions that we need to do in the near future, which are included in it.

Right. Sorry, Richard or Nigel, do you want to take, if Nigel, do you want to start, maybe Richard can jump in as well.

Certainly. So on the question of drilling campaigns and reserves versus resources what has been booked as a reserve on this asset is committed projects.

So the forthcoming EL AIN-03 well drilling campaign is part of the reserves that we carry for the assets. But we recognize there’s a significant additional drilling potential in this assets.

And John mentioned the substantial to see resource that we have that we carry on the project. The nature of the work on this asset is that there’s an awful lot of subsurface work on the presence to work up and prioritize future drilling targets.

Now, the nature of reserves bookings is that we cannot book those opportunities as reserves until the joint venture partnership have committed funds and agreed to drill those opportunities. So we will be progressively transferring to see resources into reserves as those future drilling programs mature.

John touched on the fact that we believe late in 2022, there’s going to be a further drilling campaign on this asset. The joint venture partnership has not committed to that as yet, but we envisaged that’ll happen during the course of this year.

And indeed beyond that, we already see an opportunity for a further drilling campaign out in 2023. But those are motional plans at this stage that will mature over time.

Thank you. So maybe what you’re saying is that there might be a sanction taking place in 2021, which could have an impact on the open reserve, and then there will be some more later down the line.

That is correct.

Okay. Thank you.

Good morning guys. I have three questions, If I may.

First one, just on, as far as I understand you will, of course, you are over the receipt of the cash flow that EG lifting in Q1, and that you also will have a lift in Q4, the indicators highest expected, highest of that lifting. That’s my first question.

Second question is on dividend level. Now, I think you were discussed that previously, but on what basis will you set the dividend from 2023 and going forward, will that be a percent of free cash or EPS or some kind of the number, and if also around how we should think around dividend forecasts would be useful.

And the third question to just remind us that pre- drill resource estimate for the Hibiscus North well and the Gazania well. Thanks

The first question around the EG lifting that we received the cash in April, Teodor, not in March just to clarify. So we sold the cargo in March, so it gets reflected in those performance numbers that you see.

We received the cash in April. The lifting an EG in the fourth quarter is currently targeted for around November just to see exactly when it falls.

And that’s likely to be a 650,000 barrel lifting at the moment. The one we had in March was a 950,000 barrel lifting.

So this one is probably going to be a slightly smaller move thing is our current estimate that could change. And I will certainly update you in the market when we have a little bit more visibility on that lifting and the parcel side, but that’s our current working assumption.

Your second question, sorry was…

That was around dividend and how the level…

Yes, so the dividend policy, it’s a great question. And it’s one that we – what we’ve identified obviously is with the strong cash flow we have particularly at these higher levels.

Again we designed this dividend strategy around the time when we’ve completed these acquisitions, and we designed it around sort of a long-term oil price, $45, $50 bucks a barrel. So, obviously at these higher prices it’s looking even better.

But what we decided to do is to just try and get through some of this CapEx make sure that Hibiscus reach development is on track and all that and to debate the dividend strategy, which we’d like to articulate to the market, because it’s the right question to ask. We’re not quite in a position to define it yet for you, but clearly there’s going to be particularly these oil prices quite a bit of cash.

And it’s likely to be indeed a metric along the lines that you’ve suggested. We’re not quite ready to kind of define and frame that yet, but that is very much on the board’s mind to define that better.

But as you can see, there’s quite a bit of free cash available to pay a substantial dividend. The last question is on Hibiscus North, BWE the operator have guided a range of between 10 million and 40 million barrels of prospective resource on the Hibiscus North structure.

It doesn’t take much to be commercial here because we can tie it back eventually, it’s quite close by the Hibiscus. So, even the lower end of that range of discovery is highly commercial.

On Gazania, Richard can you refresh the memory? Because we have two different targets there, a little bit on the prospective resource in that well.

So Teodor on Gazania, that well was targeting two separate stack prospects, the highest chance of success, one is the Gazania prospect itself, which is 168, I mean 168 million barrels. And the one above that is called Namaqualand, which has got a lower chance of success, but that’s slightly larger at 186 million barrels.

So combined slightly over 300 million barrels.

Okay. Thank you.

Well Daniel, the big operating costs in Dussafu is the FPSO lease, obviously there are other elements to operating costs as well and it’s largely, it’s a fixed cost. So what you’re seeing right now in terms of the operating costs being announced by the operator is as a result of the lower production at the moment, we have to go through our growth now over the next couple of years.

And so the unit cost comes down quite dramatically. I think the guidance once Hibiscus/Ruche is online, is close to $10 a barrel, and that includes the lease.

So really there is a variable cost as your production increases, but the line of share of it really is a fixed cost, more production you’re putting across. So you’ll hopefully see operating cost per barrel coming down from the early $20 at the moment down to $10, $12 a barrel or something like that once Hibiscus/Ruche comes online.

I don’t have the breakdown of exactly if we exclude the lease, how much our operating cost would be, but it is by far and away the largest portion of that. The lease plus the O&M contract on that.

I mean, Nigel, do you want to have a crack at the operating cost on EG, if we’re able to boost the production coming across the next couple of years?

Yes, John, I don’t have the numbers to handle them at my fingertips. But I guess the important thing to say here is that the OpEx itself on this asset won’t be increasing significantly with new wells.

I mean, the beauty of this project now is that we’ve got a series of platforms from which to drill new development targets and processing facilities to tie those back into. And so the costs required will be CapEx to undertake the drilling and tie back operations.

There would be some small incremental increase in the OpEx, but nothing significant. So as we drill further tranches of development wells we would expect the production to be boosted and the OpEx per barrel to be reduced proportionate to that production increase.

I hope that answers the question.

Yes. I think yes.

Yes. So it’s a little bit the same as it was last quarter, which is we have plants drilled by the Salloum West well in Tunisia, that has been held up for quite some time now on government approvals.

We’ve also had obviously COVID coming in the meantime. So we’ve been working with the regulator in Tunisia to try and come up with the best solution on that.

So we don’t have much of an update on it. I don’t think it’s a very near-term well to be drill, I think, COVID situation in large – in parts of – most of Africa now is still quite live.

The ability to get people in and out of the country from service providers things like that for drilling a well. It’s not the perfect environment to do it.

So we’re still kind of had that thing on pause at the moment. We’ll definitely update the market when that situation changes.

Nigel, I know you’ve touched on it a little bit. Do you want to just address the question, which is just, what is the operator looking at on these infill Wells?

And again, looking forward, just to make sure we answered the question?

Absolutely, John. Yes.

So it’s a very exciting stage in this assets life in fact. So typically what one does at this stage in a project’s life is create some surface static models of a geology and run dynamic simulation models of the fluid displacement within the reservoirs.

And on that basis, you identify targets for new development, well drilling. The rather unusual thing about these assets and what makes it so fascinating is that the seismic data is really very clear, and we cannot only see the reservoirs subsurface, but we can see fluid movement subsurface.

And the fact we’ve just been involved in a meeting with the joint venture partners, where that type of information is becoming apparent and a new set of seismic data that was acquired last year. So the subsurface teams have created these dynamic models.

And they’re now beginning to bring in that seismic data that can show where the water is, where some gas breakout is occurred and where the optimal target would be for development drilling of the wells. And it’s that work, that’s now informing the ranking of new development well targets for subsequent drilling campaigns.

And we’re confident that we’re going to be able to share more information on that in the months and quarters ahead as we begin to fern up those plans and sanction the forthcoming drilling projects. In the meantime, I think as part of your question, you’re asking about how the info wells will impact production levels.

What has been committed to this year is the three well campaigns on the El Ain field and the total incremental production was expected to come through at start-up of those wells is in the range of 4,000 to 5,000 barrels a day. So that’s indicative of the type of impact that we can expect to see from these wells.

But clearly as the modeling work proceeds and we firm up the next drilling campaign, we’ll have more detail on precisely what we expect in subsequent activities.

Thank you, Nigel. And this was the last question I had.

[indiscernible] from Oddvar Bjørgan. Oddvar, I have opened your line.

You may continue from…

Good morning, Oddvar.

Yes, good morning. We have been waiting for the completion of the Gabon part of the transaction.

Did you say now that you expect finalization of this within the next couple of weeks?

Yes. Very simple answer, yes.

We always got the end of the second quarter, it really just has to do with getting it through the ministerial consent basically and that’s all in good shape. So we would expect to be able to announce the closing of that transaction certainly by the end of this quarter and perhaps earlier.

Yes. Thanks.

Okay. Well, thank you everybody for joining.

We’ve got a good size crowd here today, and very much appreciate everybody following us. And again, we’re available, if anybody has any individual questions, you can always come through directly to us.

Again, thank you very much for joining.