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East Mediterranean—a mixed bag

While Egypt's gas output is set to soar, Cypriot and Israeli exports are being curtailed by regional politics and low prices. It's a mixed outlook for East Mediterranean gas

Offshore Cyprus, a Total-Eni consortium finished drilling in Block 11 in September.

A gas discovery was made, but the results were disappointing. With reserves of less than 14.16bn cubic metres, the find was too small for commercial exploitation. However, this hasn't put Eni off—the company plans to drill two offshore wells in Blocks 6 and 8, starting in late 2017. ExxonMobil plans to follow, during the second half of 2018, with two wells in Block 10. Based on the assessment of seismic data, the prospects look good, but only test wells will show whether the optimism is justified.

Some operators off Cyprus also face geopolitical uncertainties. Turkey says that part of Block 6 lies on its continental shelf, and that its claim as a mainland state takes precedence over that of an island (Cyprus). However untenable this position might be, Turkey intends to defend its assertion. Eni and Total, the owners of Block 6, are aware of Turkey's opinion, but intend to carry on with their plans. Eni has investigated the issue in detail and has substantiated the legitimacy of Cyprus' rights to its economic exclusion zone (EEZ), based on the United Nations Convention on the Law of the Sea and other relevant international agreements. On this basis, Eni and Total say they're certain about their rights to explore and exploit this and other blocks, which they won legitimately through international competition.

On the completion of all planned drilling by the end of 2018, Cyprus and the international oil companies will know the total quantity of natural gas in Cyprus' licensed blocks. However, the journey—between discoveries being made to successful exploitation and then international gas sales—is long. Global gas and liquefied natural gas prices are low and the market is bulging with supply.

Gas discoveries in the East Med are in deep water and, as a result, expensive to develop. They're also far from the growing markets in Asia. Collaboration will be key to keeping development costs down. In a low-price environment, only integrated projects, which minimise costs from wellhead to export, will stand a chance of becoming commercially viable and securing export markets. And even these ventures will face difficulties.

20-35bn cm/y - Egypt's expected gas surplus by 2030

Israel faces similar challenges in its attempts to secure export markets for natural gas from its giant offshore Leviathan field. There are three main export options on the table; to Turkey by pipeline for domestic use there, and/or export from there to Europe, to Egypt by pipeline for the domestic gas market, or exporting as LNG, or to Europe through the EastMed gas pipeline passing through Cyprus, Greece and Italy.

All these options are commercially challenging. Not least because it's difficult for Noble Energy—Leviathan's operator—to charge foreign buyers less than the minimum in the Israeli domestic market, currently $4.70 per million British thermal units.

Given the difficulties involved in reaching the gas regulatory framework agreement in 2016, if gas was sold to an international company at a discount, then there would be pressure for Noble to supply gas to the domestic market at the same level. Significant Israeli public opposition could be expected if the export price was lower than that for exports.

As for the option of Israeli exports to Turkey, by the time the cost of the pipeline is added to that of gas at the platform, the landed price would be higher than imports from Russia or Azerbaijan. There are also political problems arising from the pipeline passing through Cyprus' EEZ. Without a solution to the Cyprus problem, the government in Nicosia wouldn't grant its consent to a project benefiting Turkey.

Even if such a pipeline became possible, transit costs would make extending it from Turkey to Europe highly uncompetitive when compared to prevailing European gas prices.

Similar commercial challenges apply to gas from Israel to Egypt. Another obstacle, in addition to political problems, is the unresolved $2bn International Court of Arbitration award against the Egyptian Natural Gas Holding Company (Egas) and the Egyptian General Petroleum Corporation for halting gas supplies to Israel in 2012.

Export obstacles

A joint declaration by the energy ministers of Israel, Cyprus, Greece and Italy, in the presence of European Commissioner on energy Miguel Arias Cañete, at a meeting in Jerusalem in April 2017, put the EastMed gas pipeline back into the limelight. The proposed pipeline is considered to be a strategic project for exporting East Med gas, and the aim is to create a direct export route from the region to Europe by 2025.

A preliminary engineering study was completed in late 2016 by IGI-Poseidon, a joint venture between Italy's Edison and Greece's gas corporation, DEPA, funded by the European Union as a "project of common interest". The study claims that the proposed pipeline is both technically feasible and commercially viable. The estimated cost of the project as far as Italy is about $6.4bn, but this is considered by experts to be highly optimistic. In any case, adding this to the cost of gas at the platform makes the landed price too high in comparison to prevailing prices in Europe.

This leaves Israeli gas short of viable export options, a factor which, when combined with the country's history of regulatory risks, is having an impact on its current offshore licensing round. Despite already been extended twice—the new deadline being 15 November—interest from IOCs has been limited.

Lebanon kicked off its first licensing round by offering up five blocks for bidding: 1, 4, 8, 9 and 10. The awards are expected by mid-November. Unfortunately, Block 1 is on the disputed border between Lebanon and Syria, and Blocks 8, 9 and 10 include areas disputed by Israel. This may complicate the process. As a result, even though the government pre-qualified more than 50 companies, it remains to be seen how many serious bids have been received.

In a low-price environment, only integrated gas projects will stand a chance of securing export markets

The good news, though, is that on 19 September the Lebanese parliament passed legislation to regulate the tax regime relating to oil and gas operations. This is an important milestone, but it's unclear if the new measures will inject life into the bidding round.

Egypt expects to become self-sufficient in gas by end-2018 and resume exports by 2021. Due to misguided policies in the past, gas production fell significantly between 2011 and 2016. Since then it has risen again, reaching 53bn cm so far this year, after hefty gas delivery price rises to IOCs—up to $5.88/mBtu.

Egypt had been importing 12bn cm a year of LNG, but announced in September that it was reducing this by 30% due to increased domestic production. Egas and the Ministry of Petroleum said that 2018 should be the last year the country would need to import gas for the domestic market, with new production more than covering demand. Egas is also planning to issue global tenders for concessions in Egypt's west Mediterranean in 2018. In addition, Egypt plans to produce 20% of its power demand from renewables, including hydropower, by 2022.

The country's Petroleum Minister Tarek al-Molla said that 2017 would witness a quantum leap in Egypt's natural gas production. Eni confirmed that the offshore Zohr field, with 850bn cm of reserves, will achieve first gas in December at an initial rate of 5 bn cm/y, ramping up to 10bn cm/y during the first half of 2018, and reaching a plateau of 28bn cm/y by 2019.

BP started production from its West Nile Delta concession in May this year and expects to reach 15bn cm/y from this and its North Alexandria projects by 2019. A total of 12 gas projects under development are expected to bring an additional 55-65bn cm/y of gas on stream by 2020. On this basis, Egas and the Ministry of Petroleum expect Egypt to resume gas exports by 2021, making full use of the existing LNG plants at Idku and Damietta.

Strong domestic demand will underpin this growth. The International Energy Agency expects gas demand to increase by 4-5% per year over the next five years, in line with expected economic growth. Having implemented International Monetary Fund recommendations, Egypt's economy is on the road to recovery. Gas surplus for export could reach 20-35bn cm/y by 2030, possibly more. This will exceed the existing combined liquefaction capacity of Idku and Damietta LNG plants—17.5bn cm/y.

The rapid expansion of Egypt's gas sector will strengthen the country's ambition to become the gas hub in the East Med. Egypt's recent decision to liberalise its gas market, to allow open and free trading by private buyers and sellers, will further improve its chances of achieving this.

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