Charles Ellinas Gas Exports to Egypt and Implications

Gas Exports to Egypt and Implications



Over the last few days there has been a lot of activity, government discussions and press coverage about gas exports is Egypt. But developments in the region and beyond may challenge this.

In March Cyprus Hydrocarbons Company (CHC) and the Egyptian EGAS signed a memorandum of understanding for a feasibility study into a subsea pipeline for exporting the gas to Egypt. And press articles this week refer to gas exports of 700 million cubic feet per day and agreements about to be signed, presumably MoUs. But what really matters is to have in place firm, binding, gas sales agreements. Once these are in place, infrastructure, finance and construction are not major issues.

Egypt faces domestic gas shortages and has already entered into various agreements to import LNG over the next few years.

However, the need to import gas for domestic use is short term. Egypt believes concessions awarded to IOCs over the past year, such as BP, ENI, Total and BG, underpinned by new discoveries in the Nile Delta, will restore the country to energy self-sufficiency by 2018 and stop the need for gas imports by 2020. In addition, domestically produced gas would cost between $3.50-$5.00 per mmBTU, whilst gas piped from Cyprus would cost between $7-$8.

On this basis it is difficult to see how this could help the development of Aphrodite. Not only it is expensive gas in comparison to Egyptian gas, but by 2019 when the Aphrodite project can be completed Egypt will no longer require gas imports.

Discussions are currently under way to export gas from Aphrodite to Egypt’s under-utilized LNG plants at Idku and Damietta. This faces a number of serious challenges. MOUs have been signed with Leviathan and Tamar to supply gas that will take about 70% of the capacity of the two LNG plants, with the remainder taken by BG and BP gas in Egypt. Also prices for LNG delivered to Europe and Asia are about $7 per mmBTU. The cost, excluding profits, of transporting Aphrodite gas to Idku, liquefying it, shipping to Europe and regasifying it may be of the order of $11 per mmBTU. This may make such a project uneconomical at least for the time being.

A new factor is the acquisition of BG by Shell. It remains to be seen how Shell deals with Idku, Israeli and Cypriot gas, especially given its major interests and investments in Turkey and the Arab world, combined with Shell’s lack of appetite for pursuing further production in Egypt. This acquisition will not be completed until H1 2016. In the meanwhile it is unlikely that BG will embark on any major new undertakings in Egypt, until the acquisition is complete and Shell has finalized its strategy.

Should the Egyptian option not proceed, there will be inevitable delays before other options are studied and followed. With prefeasibility studies already done by Noble, this can be partly overcome by pursuing export of Aphrodite gas to Southeast Europe by CNG.

If this is not followed, with the Egyptian option becoming increasingly challenging, both for Cypriot and Israeli gas, other options considered in the past but not pursued may now gain momentum.

With Total and ENI on the back-foot for the next couple of years there is a period during which to concentrate on the Cyprob discussions, consider other export options and prepare for a third licensing round given that by then oil price recovery will be well on the way and interest may be rekindled. There are good indications that East Med contains substantial quantities of gas to be found through renewed exploration activity. But all this requires planning.

charles.ellinas@yahoo.com


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