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ENI-SGN gas not priced higher than others

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Adnan Adams Mohammed
There is a wide spread of malicious and untruth information about ENI operated Sankofa Gye Nyame (SGN) projects gas pricing which seems to suggest that, SGN gas price is higher than the price of Nigeria Gas (that is landed in Ghana through the West Africa Gas Pipeline), Jubilee field gas and TEN field gas which are landed at Ghana Gas at Atuabo.
One fundamental logic that those spreading the false information are forgetting is that, gas prices from associated fields like Jubilee and TEN cannot be compared to gas prices of non-associated fields because the economics on the cost recovery of the Jubilee and TEN project is based on the sale of the Oil (and not the gas) whereas the economics of the SGN project relies on the sale of the gas since the SGN fields are predominantly non-associated gas.
Available figures, also, diffuse this untruth information given that, the net Gas price that Ghana pays to ENI is less than the landed gate price cost of Nigerian Gas. Ghana currently pays almost US$8.8 per mmBTU for Nigerian Gas whereas Ghana will be paying on a net basis less than US$6.0 per mmBTU for landed SGN gas at Sanzule.
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Further details on the gas price for the SGN project are based on cost recovery and an acceptable Rate of Return (RoR) for such risky Deep-water E&P projects. Again, the Gas price has not been negotiated downwards by anyone; to explain further, this is because the agreement negotiated but GNPC and signed in 2014 provided that all development cost savings from the originally estimated development cost in the Plan of Development (PoD) would be used to reduce the Gas price; consequently, every US$100 million savings in project cost would translate to a US$0.55/mmBTU savings in gas price.
In a recent article authored by former GNPC Boss, Alex Mould, he noted that, in the development of a deep water oil and gas project, whether ENI was to develop the project or GNPC was to develop the project, the cost would be about the same; maybe less should ENI raise the financing directly mainly because ENI as the single “A-rated” company or at worst B+, can raise funding cheaper than Ghana Government which is army beat Single B-rated.
“Given that the project is a 20 to 25-year project, we have to look at the total economics of the project (all the cash out flows for costs and the revenue cash flows) to decide whether we want to embark on this project or not based on a Net Present Value analysis using the agreed rate of return hurdle rates of all stake holders; that was the main criteria for negotiation between ENI and the government of Ghana.
“Unlike Jubilee field development, which is a pure oil project at time of development where there was no gas revenue at time of approving and sanctioning the project, ENI had to make a decision whether they would invest in ‘SGN field’ development which has only about 150million barrels of oil (oil in condensate combined).  It also had gas of approximately an additional 180/190 million barrels of gas equivalent. That was the data they submitted to us in the plan of development.”
He continued, “If you look at the amount on the gas, it is much larger than the oil and the revenue or the economics of the oil alone will not be able to support the development of this project. So the only way this project could be developed is if gas and oil field are developed as an integrated project and that was the decision the government took at that time, that yes we want the gas to be the driver of this project. In summary, it is predominantly a gas field development that was approved. The oil is going to be 40,000barrels a day for about five years and it drops to 20,000bbls for the next 3 years, and finally dwindles to about 10,000bbls.
“No financial institution or no investor would invest in the SGN project only based on the oil flows. The only way an investor would invest in this particular project is if the gas was included. Now we had a big problem with the gas because they had an alternative to liquefy the gas and export it which would then make the risks and economics similar to that of an oil only development; but the Gas quantities and economics could not support a liquefaction plant.”
We need to know that, with oil it’s quite easy to finance, because there is very little country risk in the off taker. First of all, the field is offshore gas. Secondly, the off-taker would be an international trader or a refinery of repute like TOR. So anybody who is financing this project would look at the risks and economics of the project and the rate of return and also the financing cost. They would also want to know whether financing institutions would be able to get enough banks that have country risk for that tenure.
More so, most banks have country risk for one year, some even six months. When you go to three years, the number of banks drops exponentially that would finance a Ghana project with that tenor. With tenors of ten years and over there will be only a handful of banks which I can count on my fingers on one hand.
It also depends on what support government is going to give to the project. If government is not going to give any support there would be no bank. I can assure you that for a 10year gas development project with no government support there will be zero Banks interested.
This particular sector is very technical. , it is very financial and a lot of people are misconstruing based on literature that they are reading. I even heard somewhere someone said the cost of recovering oil from the ground is US$10/bbl. Jubilee field which is a world class field has reserves than can produce at over 100,000 bbls a day for at least 10-15 years. Even for such a world class field, because of the high cost in developing and producing the oi
l in deep water approximately US$700-US$1000million below the sea level and with deposit of US$3000-5000million below dear bed, the cost of producing oil from Jubilee is more than US$24/bbl especially in the first 5-10 years.
Because of its reserves and production profile, Jubilee is a world class field. There are not many world class fields in the world. TEN nor SGN are not a world class fields. The cost of producing this oil has been misconstrued to make people think that the people negotiating on behalf of the Government of Ghana know nothing and don’t have data to support the negotiations. The negotiations that are done, whether you do it by tender or you do it by concession, or by direct negotiations, is all dependent on the economics. How much is the investor prepared to take as the rate of return for the risk he is taking, that is, the project hurdle rate?
For some comparison on rate of return investors are prepared to accept let’s look at some examples; Ghana government’s instruments like T’Bills and Government Notes and Bonds issued by BoG on behalf of GoG is deemed “risk free assets”, that is, almost zero risk in Ghana; yet investors in GoG 10Yr bonds in Ghana are paying 19% in Ghana cedis and almost 10% for same risk dollar bonds. An investor who is investing in  ‘Ghana risk’ with the added risk of an offshore field, deep water – very risky conditions – would  expect higher rate of returns than GoG Bonds of similar tenors.
The price of gas from such a development will depend on the amount of reserves you have, how fast you are going to produce them, and the cost of the project, and the return to the investor. There is no magic; if you change the rate of return you get a different gas price. If you change the cost of development, you get a different gas price. If you change the amount of reserves you get a different gas price.
Mr Mould relate that, at the time when the petroleum Plan of Development (PoD) was delivered, certain assumptions were made, they assumed how much reserves they can extract from the field based on the science – not the actuals but projections backed by science. They assumed the cost of the project of about US$7.3 billion which includes the cost of the FPSO lease and operations for 20 years.
“All of these were assumed in the PoD document that went to the ministries. Of course, the ministry had to consult with all the stakeholders involved like GNPC, Petroleum Commission, most likely in Parliament. It’s a public document. It is stated exactly how this project is going to be financed based on how the assumptions are made. It was also stated that if there were any costs savings it would reflect in the price of gas not the price of oil. The project cost would split between gas and oil. Any savings on the project would only affect the gas price and that is where the focus should be because there were significant savings at the time of doing this project oil prices were about 45 dollars. The time the PoD was submitted the oil prices were in the 80/90 dollars range.
“By the time of executing the project prices of oil had dropped and prices had also dropped on the services. In the negotiation on the gas price the first data that were received were savings of US$691 million which translated into some good savings of 55 cents per hundred million. All of a sudden the savings dwindled from US$691 million to about less than US$200 million. Why? How transparent was that? There were other costs to be incurred. In the agreement, GNPC was supposed to bear those costs. Why?
“If you have a project, an overall project where the rate of return is greater than 10% and you can finance less than 10% why would you let somebody finance it. GNPC decided that they could raise some money 5 to 6% maybe lower than government and finance these additional part of the project which were not as risky as drilling the E&P.”
The former GNPC Boss revealed that, “GNPC was supposed to raise the money. GNPC had access to raise the money. What did GNPC do with the money; they rather lent it to BOST instead of using the money for the project. So at the time that they were supposed to finance it, they didn’t have the money to do it. So they had to go back to ENI. When they went back to ENI, this savings dwindled from US$691million to less than US$200million.
“So the price that was set at US$9.8 which would then have benefited for the deductions from the savings of 691million now is going to result in less than $1.80 per mmBTU thus reducing the price from $9.8 to only US$8.10/mmBTU. We should have allowed the total reductions in final gas price to be based on the 691million savings. We should then have gone and sat down with ENI and our financiers to see how we are going to finance the remaining amount of how much it was going to cost. If we had done the calculation we would have realized that it was better for us to reduce the gas price than to allow ENI or somebody else to invest in this.” 

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