Charles Ellinas
This week’s deal with Noble, Delek and Shell divvying up the profits from the Aphrodite gas-field is not quite what it seems at first glance
The good news is that an agreement has been reached between the government and the Noble Energy, Delek and Shell joint venture (JV) on a revised Production Sharing Contract (PSC) for the development of the Aphrodite gas-field.
Based on published reports the agreed profit split is now about 57 per cent to Cyprus and 43 per cent to the JV, when the price of oil is $70/barrel – with Cyprus’ share going up when the oil price goes up and down when the oil price goes down. With long-term forecasts estimating the average oil price range to be $60-$70/barrel, there can only be a downside for Cyprus. That’s why the JV was so keen on this renegotiation.
There are also new provisions to ensure development of Aphrodite within a strict timetable, with penalties to the JV if it is not. This of course is what the JV wants too – to develop the project as soon as possible.
There was a missed opportunity to insist on the construction of a subsea pipeline to bring competitive gas from Aphrodite directly to the electricity authority, the EAC, in return for the concession on profit sharing. I covered this in my article last Sunday.
Nevertheless, it is not a bad agreement and it is now in line with the other PSCs with Eni, Total and ExxonMobil. And it opens the way for negotiating and completing a gas sales agreement with the Idku liquefaction plant in Egypt, which would expedite development of Aphrodite – assuming of course that this is commercially viable, based on gas quantities and price.
The drawback of such a deal is that it would set back the possibility of building a liquefaction plant (LNG) in Cyprus by years, as it leaves insufficient gas to do so. Something like 10-15 trillion cubic feet (tcf) gas is needed for such a project, and the combined reserves of Calypso and Glafcos (with 90 per cent probability) are about 7 tcf. So, an LNG plant at Vasilikos will have to wait until more discoveries are made during the next planned drilling round in 2020-2021.
Let’s now look at reported profits from such a sale.
Reported profits from Aphrodite
There has been considerable publicity on this during the last few days. Let’s look at the reported numbers. Cyprus’ share of the profit from the sale of Aphrodite gas is reported to be $9.5 billion. This corresponds to 57 per cent of the profits in accordance with the revised PSC. So the total profit would be $16.7 billion. The development cost, including operations and maintenance, is reported to be $8 billion. This means that total revenue from selling the gas would be $24.7 billion.
These numbers suggest a 68 per cent project profit – remarkable! Even in the good old days of high oil and gas prices, oil companies would have been very happy to achieve 25 per cent. Given that we are in low oil and gas price era, for the longer-term, such profits are extremely optimistic.
But let’s continue the analysis. Relying on reported data, these revenues are based on 4.1 tcf of gas. However, this corresponds to a 50 per cent probability estimate. Project development, and bank finance, are normally based on 90 per cent probability estimates – in this case about 3.1 tcf. And even then not all of it is recoverable. Usually about 80 per cent of gas-in-place is recoverable, in this case about 2.5 tcf (based on 90 per cent probability). Incidentally, this would enable 7 billion cubic metres (bcm) per year gas sales from Aphrodite to Idku for 10 years – exactly what has been reported to be the likely contract with Idku.The Idku plant will liquefy, ship the LNG to Europe, where it will be regasified, and then delivered to European clients
There are also additional uncertainties. The Aphrodite reservoir is fractured and divided into non-communicating compartments. Only two of these compartments have been explored so far. The first, exploratory, well was drilled in 2011 and resulted in gas-in-place estimated at the time to be about 7tcf (50 per cent probability). The second, appraisal, well drilled in 2013 resulted in the much reduced estimate we know today, 4.1 tcf. Further planned appraisal drilling was subsequently deferred. This still needs to be carried if Aphrodite’s gas reserves are to be estimated with greater accuracy – and they can go up, but they may be even lower, as the 2013 experience shows.
But let’s take the 4.1 tcf estimate. Based on this, in order to realise $24.7billion revenues, Idku must pay the JV $6/mmbtu (per about 1000 cubic feet). Idku will then liquefy, ship the LNG to Europe, where it will be regasified, and then delivered to European clients, after including profits.
Current gas prices in Europe are close to $4/mmbtu. Longer-term forecasts estimate that the average price in the period to 2030 will be $6.50-7.50/mmbtu. After paying the JV $6/mmbtu, that would leave Shell with $0.50-1.50/mmbtu to pay for all above costs and make a profit – an impossibility.
The reported profits are very optimistic, to say the least. As I said before, final investment decisions (FID) to sanction a project would be based on 90 per cent calculations. Let us consider what this means for potential profits.
Estimated profits
Let’s look at the potential profits from selling Aphrodite’s gas. The 90 per cent probability gas reserves is about 3.1tcf, with about 2.5tcf recoverable.
The JV is reported to be close to selling the gas to the Idku liquefaction terminal in Egypt for liquefaction and export. Shell is the majority shareholder in Egyptian LNG, the operator of Idku. Existing Idku contracts are mainly for export of LNG to Europe.
Gas prices in Europe over the next decade are expected to average around $6.50-7.50/mmBTU. Taking into account cost of liquefaction, taxes, shipping, LNG regasification costs and profit, Idku is likely to pay the JV about $3-4/mmBTU for gas delivered to the terminal.
The cost to produce the gas and deliver it to Idku includes drilling, construction of production facilities, the subsea pipeline to Idku, cost of financing and insurance and the cost of operations and maintenance. Once these costs are deducted, the likely total profit to the JV is expected to be between $1.1-3.2billion. The share of Cyprus will be 57 per cent, ie between $0.6-1.8billion. If the sale period is 10 years, this amounts to approximately $60-180 million per year.
It is prudent to be conservative in our assessments. This is how projects are sanctioned. Then the risk is minimised. If later more gas becomes recoverable, that would be a welcome upside.
But there is still the unresolved problem with the Ishai Group and Israel over the unitisation agreement because of a possible extension of the Aphrodite to the neighbouring Ishai block. This requires an urgent solution if, with the development of Aphrodite, escalation of the dispute, ending in international courts, is to be avoided. In such an eventuality Cyprus risks to lose. Net profits to Cyprus and the JV will have to allow for such a settlement.
Dr Charles Ellinas is a senior fellow at the Global Energy Center of the Atlantic Council
SOURCE
This week’s deal with Noble, Delek and Shell divvying up the profits from the Aphrodite gas-field is not quite what it seems at first glance
The good news is that an agreement has been reached between the government and the Noble Energy, Delek and Shell joint venture (JV) on a revised Production Sharing Contract (PSC) for the development of the Aphrodite gas-field.
Based on published reports the agreed profit split is now about 57 per cent to Cyprus and 43 per cent to the JV, when the price of oil is $70/barrel – with Cyprus’ share going up when the oil price goes up and down when the oil price goes down. With long-term forecasts estimating the average oil price range to be $60-$70/barrel, there can only be a downside for Cyprus. That’s why the JV was so keen on this renegotiation.
There are also new provisions to ensure development of Aphrodite within a strict timetable, with penalties to the JV if it is not. This of course is what the JV wants too – to develop the project as soon as possible.
There was a missed opportunity to insist on the construction of a subsea pipeline to bring competitive gas from Aphrodite directly to the electricity authority, the EAC, in return for the concession on profit sharing. I covered this in my article last Sunday.
Nevertheless, it is not a bad agreement and it is now in line with the other PSCs with Eni, Total and ExxonMobil. And it opens the way for negotiating and completing a gas sales agreement with the Idku liquefaction plant in Egypt, which would expedite development of Aphrodite – assuming of course that this is commercially viable, based on gas quantities and price.
The drawback of such a deal is that it would set back the possibility of building a liquefaction plant (LNG) in Cyprus by years, as it leaves insufficient gas to do so. Something like 10-15 trillion cubic feet (tcf) gas is needed for such a project, and the combined reserves of Calypso and Glafcos (with 90 per cent probability) are about 7 tcf. So, an LNG plant at Vasilikos will have to wait until more discoveries are made during the next planned drilling round in 2020-2021.
Let’s now look at reported profits from such a sale.
Reported profits from Aphrodite
There has been considerable publicity on this during the last few days. Let’s look at the reported numbers. Cyprus’ share of the profit from the sale of Aphrodite gas is reported to be $9.5 billion. This corresponds to 57 per cent of the profits in accordance with the revised PSC. So the total profit would be $16.7 billion. The development cost, including operations and maintenance, is reported to be $8 billion. This means that total revenue from selling the gas would be $24.7 billion.
These numbers suggest a 68 per cent project profit – remarkable! Even in the good old days of high oil and gas prices, oil companies would have been very happy to achieve 25 per cent. Given that we are in low oil and gas price era, for the longer-term, such profits are extremely optimistic.
But let’s continue the analysis. Relying on reported data, these revenues are based on 4.1 tcf of gas. However, this corresponds to a 50 per cent probability estimate. Project development, and bank finance, are normally based on 90 per cent probability estimates – in this case about 3.1 tcf. And even then not all of it is recoverable. Usually about 80 per cent of gas-in-place is recoverable, in this case about 2.5 tcf (based on 90 per cent probability). Incidentally, this would enable 7 billion cubic metres (bcm) per year gas sales from Aphrodite to Idku for 10 years – exactly what has been reported to be the likely contract with Idku.The Idku plant will liquefy, ship the LNG to Europe, where it will be regasified, and then delivered to European clients
There are also additional uncertainties. The Aphrodite reservoir is fractured and divided into non-communicating compartments. Only two of these compartments have been explored so far. The first, exploratory, well was drilled in 2011 and resulted in gas-in-place estimated at the time to be about 7tcf (50 per cent probability). The second, appraisal, well drilled in 2013 resulted in the much reduced estimate we know today, 4.1 tcf. Further planned appraisal drilling was subsequently deferred. This still needs to be carried if Aphrodite’s gas reserves are to be estimated with greater accuracy – and they can go up, but they may be even lower, as the 2013 experience shows.
But let’s take the 4.1 tcf estimate. Based on this, in order to realise $24.7billion revenues, Idku must pay the JV $6/mmbtu (per about 1000 cubic feet). Idku will then liquefy, ship the LNG to Europe, where it will be regasified, and then delivered to European clients, after including profits.
Current gas prices in Europe are close to $4/mmbtu. Longer-term forecasts estimate that the average price in the period to 2030 will be $6.50-7.50/mmbtu. After paying the JV $6/mmbtu, that would leave Shell with $0.50-1.50/mmbtu to pay for all above costs and make a profit – an impossibility.
The reported profits are very optimistic, to say the least. As I said before, final investment decisions (FID) to sanction a project would be based on 90 per cent calculations. Let us consider what this means for potential profits.
Estimated profits
Let’s look at the potential profits from selling Aphrodite’s gas. The 90 per cent probability gas reserves is about 3.1tcf, with about 2.5tcf recoverable.
The JV is reported to be close to selling the gas to the Idku liquefaction terminal in Egypt for liquefaction and export. Shell is the majority shareholder in Egyptian LNG, the operator of Idku. Existing Idku contracts are mainly for export of LNG to Europe.
Gas prices in Europe over the next decade are expected to average around $6.50-7.50/mmBTU. Taking into account cost of liquefaction, taxes, shipping, LNG regasification costs and profit, Idku is likely to pay the JV about $3-4/mmBTU for gas delivered to the terminal.
The cost to produce the gas and deliver it to Idku includes drilling, construction of production facilities, the subsea pipeline to Idku, cost of financing and insurance and the cost of operations and maintenance. Once these costs are deducted, the likely total profit to the JV is expected to be between $1.1-3.2billion. The share of Cyprus will be 57 per cent, ie between $0.6-1.8billion. If the sale period is 10 years, this amounts to approximately $60-180 million per year.
It is prudent to be conservative in our assessments. This is how projects are sanctioned. Then the risk is minimised. If later more gas becomes recoverable, that would be a welcome upside.
But there is still the unresolved problem with the Ishai Group and Israel over the unitisation agreement because of a possible extension of the Aphrodite to the neighbouring Ishai block. This requires an urgent solution if, with the development of Aphrodite, escalation of the dispute, ending in international courts, is to be avoided. In such an eventuality Cyprus risks to lose. Net profits to Cyprus and the JV will have to allow for such a settlement.
Dr Charles Ellinas is a senior fellow at the Global Energy Center of the Atlantic Council
SOURCE
