Angola’s deepwater dynamics and onshore prospects

Angola

Carlos Amaral, general manager of Acrep, talks to The Energy Year about Angola’s deepwater E&P dynamics, challenges in operating sustainably onshore and the company’s plans to become an operator. Acrep is an Angolan upstream company with a focus on developing Block 1/14 and the Cabinda North block.

How would you characterise Angola’s deepwater E&P scene?
Angola has been quite successful in the offshore. About 95% of the national production used to come from the deep offshore. And we have had unexpected success in the deepwater and ultra-deep, where we are still very young. In spite of not having big discoveries, we have drilled fewer than 25 exploration wells and had at least 8-10 discoveries, which is a very good success ratio.
Of course, discoveries don’t equate to commercial production. You cannot just go into the pre-salt and expect to find oil on day one. In Brazil’s pre-salt, it took 25 years for Petrobras to get where they are today. The deepwater E&P was quite active in the pre-salt because companies were in the mood to develop frontier discoveries with frontier equipment. The only way to optimise costs is being able to design and create equipment such as subsea installations, compressors, pumps and so on, which minimises the costs of moving the production to shore.
However, the deep offshore has a big problem. Maintenance is very expensive. That’s why Angola’s production is coming down – because maintaining production in the deepwater is quite complicated and very expensive. The oil price averaging USD 60 forces us to rethink any deep offshore project.

What are the cost dynamics shaping Angola’s oil production?
In new fields, for the first five or six years, the cost of producing a barrel is USD 6-8, which is the norm. TotalEnergies, on existing fields, has an around that average. On Block 4/05 we have a much higher figure, around USD 45 per barrel, which breaks even, but we have a very small production and a very big cost from the FPSO rental fee.
The difference for majors is that they don’t rent FPSOs; they buy them. Their advantage is that when they invest as capex, they get a premium on investment of 30%. If an FPSO costs USD 500 million, with a premium of 30% you already make a USD 150-million gain. This is referred to in the PSA as the uplift.
A company with access to easy money, or which has money like a major, generally makes more money on capex than on operations. In contrast, if a company like Acrep is going to rent an FPSO at USD 100,000-150,000 a day, it has to produce at least 3,000 bopd at USD 50 to just pay the FPSO fees, which means the whole business lives or dies by slight changes in the price of oil.

What are the still existing challenges for local companies trying to operate sustainable projects onshore?
It is remarkable that the ANPG [National Oil, Gas and Biofuels Agency] managed to finalise the 2021 bidding round under these unstable global conditions. But the ANPG and the petroleum ministry have considered onshore as a different concept. Production-sharing agreements are no good for locals willing to enter the onshore because we have to capitalise the company via the concession. Local companies have to buy drilling rigs in order to optimise the activities, be it exploration or production, and at the end of two or three years when the drilling rig is finally paid for, it can move into other areas .
For locals operating onshore, the contract should not be a PSA. We should not share the profit; we should just pay our taxes. Companies in the US have value onshore because the US has a different legal system, in which anything that is on the land is the company’s property. But we have the French system, which is different.
Onshore is much more accessible but more expensive than offshore because you have to build roads, relocate people and take care of the environment. You are permanently monitored by the population.
A good drilling success ratio onshore is 10%, which means you have to drill a lot. Ideally you should have a big enough area to justify drilling 10 wells. But to do that, you cannot rely on contractors. You have to be able to have your own machine and your own team – it’s cheaper, and you can drill more. We should be required to invest in buying, for example, a drilling rig second-hand for USD 3 million.

How does the size and location of these onshore blocks affect their commercial viability?
It’s great that the ANPG is reopening them and considering Angolan companies. Oil was discovered there when Petrofina was exploring it as a single block. If Petrofina had achieved anything good there, they would never have left. It’s a mature area that should not be re-explored; the existing Kwanza/Congo onshore blocks should be offered for re-optimisation. What we are trying to do is to drill areas with existing exploration, which unfortunately and most probably will not produce good results: let’s see what the future tells us.
The Kwanza Basin should have been offered as one concession, not five or six small blocks. If you don’t have a drilling rig, and have only a very small area to explore and a contract requiring you to drill only two or three wells, you are getting into an unviable business.
Angola has five or six interior basins. Those are the ones that need to be explored. The energy transition has put us in a situation where we need to take action in the next 10-12 years. The funds are not the only problem – today people don’t believe we should be drilling holes near their homes.
If foreign oil companies were to disappear from Angola, there ought to be local companies that could take over, like in Nigeria, which has a lot of marginal fields. In Angola, because of the war, the onshore was quiet for 40 years. Now we have to expedite onshore, to explore these five or six onshore basins and participate in development of those areas by generating power, creating employment and producing petrochemicals.

What is Acrep’s plan for floating its shares on Angola’s stock exchange?
This is a central part of our regeneration strategy. We are working with an intermediate financier to determine the company’s real market value. By Q3 2022 we will know whether or not we have the conditions to be on the joint-stock exchange. We might float a base of 55% of the company’s shares, but we continue negotiating with companies that are interested in acquiring Acrep.
The stock exchange will eventually allow us to be funded in both kwanzas and USD. Angolan companies work in Angola; therefore we have to learn how to do things without counting too much on USD. As an onshore operator, very few costs do have to be paid in USD, except for acquisition of drilling equipment, such as drilling rigs and associated well completion equipment, and the rest can be majority paid for in kwanzas.
We see ourselves as having a good portfolio to attract small or medium-sized companies that would like to enter the market without losing money, to operate in Angola and to help us become an operator.

Can you give us an update on Acrep’s assets and main projects?
We are concentrating more on becoming operators onshore, and following a specific strategy in order to do this.
In Block 4/05, Sonangol P&P announced they will farm out 20% of their share. Acrep is also open to selling its 18.75% share in this block. We are further considering divesting from Block 2/05 in order to enhance our finances and secure funds for operating onshore. Beyond that, we’re considering diversification, and not necessarily in energy.
We are concentrating our exploration efforts on Block 1/14, which we joined in 2021 with Eni, Equinor and Sonangol P&P. A 3D-resolution seismic survey has been done all over the block, and we expect to have the first exploration well drilled in 2024. There is quite a good potential. That’s why there are two majors involved, and for us it’s important to be aligned with key majors.

What are the steps ahead for Acrep to fulfil its onshore operatorship goal?
We have invested a lot in the onshore Cabinda North block and we have a discovery of 200 million barrels of oil in place. If you consider 10-15% recoverable, you could be talking about a potential 20 million-30 million barrels to be recovered. This is not a high volume for our partners in the contracting group [the joint venture of Eni, Sonangol P&P, WM and Acrep]. But for Acrep it could be a starting point to stop being just part of a contracting group and to take an active role, with the vision of achieving onshore operatorship soon.
I believe that if after 17 years we don’t have a block to operate, Acrep has achieved nothing. We will concentrate our efforts in Cabinda North and we will look to onshore Cabinda for other opportunities. It has a lot of potential for tight oil – again, not good for the majors, but something that can be good for a small company.

How could the Cabinda Refinery’s completion affect the competitiveness of onshore production in the area?
President João Lourenço recently announced that the refinery’s 30,000-bpd train will be inaugurated in 2022. He was quite right when he emphasised how little Angola had built after 45 years of oil production, saying we have remained refined oil buyers with no downstream industry.
If you have a small company producing 300 bopd onshore near Cabinda, you need a refinery nearby to generate a stable demand that can protect you from the instability of the oil price. If you have a stable demand for 10 years, you can do all sorts of other investments – drilling more wells, optimising production and so on. When you have a fixed client, banks can lend you money.
We still pretend that local companies producing 1,500 bpd can behave like Eni or Shell, but they need this certainty. The only way you can consider looking at the onshore potential is if you have a stable client. Angolan companies should not be worried about exporting oil. They should be able to count on a fixed price from a local refinery.

How is Angola adapting to energy transition trends?
Angola has already achieved one of the world’s highest targets for the transition: around 60% of our energy is green. 50% comes from hydropower, and some 10% or so from natural gas.
The private local companies don’t need to follow the transition as such. We need first to gain control of the business and to produce oil. As long as we produce energy under good conditions for the environment and society, we should be able to seize our resources.

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