This article was written in May for the June edition of Executive Magazine.
The third well drilled in Cyprus’ Exclusive Economic Zone (EEZ) failed to reveal commercially exploitable natural gas reserves. Italian multinational Eni’s Saipem 1000 drillship drilled to a depth of 5,485 meters in Amathusa, in Block 9, without yielding positive results.
This is the second failed attempt by the Eni-KOGAS consortium in Cyprus’ EEZ. The consortium is hoping to get similar treatment to that given to Total, and submitted a request to extend its exploration license. As it stands today, the license expires in February 2016, with the consortium negotiating with Nicosia for a two year extension. Eni reportedly plans to use this period to form a more precise picture of the previously unexplored area and reevaluate the geological model and data collected in both drills.
With Total and Eni’s failure to locate commercially exploitable quantities of natural gas, all five blocks awarded in the second licensing round to big fanfare in 2013 yielded disappointing results. Of course, this does not rule out positive results in the future with the possible extension of the exploration program — granted for Total, and hoped for by Eni.
Exploratory drilling on hold
If Eni’s failure in Onasagoras and Amathusa, both in Block 9, is in itself a setback for Cyprus (although not entirely unexpected given the success rate for drilling at such depths), it does not mark the end of bad news for Nicosia. The Eni-KOGAS consortium, which holds exploration rights in Blocks 2, 3 and 9, is legally bound to drill at least four wells in its current exploration program. But, after two unsuccessful wells and over $300 million spent, the program is shrouded in doubt. No exploratory drilling is expected this year in Cyprus (the Saipem 1000 drillship is scheduled to undergo maintenance lasting around five months) and could possibly be delayed for much longer. Indeed, with current oil prices, the Italian company has suffered significant losses in the last quarter of 2014, leading to cutbacks and the decision to sell up to €8 billion ($8.9 billion) of assets. Its priorities seem to lie a bit further south, after pledging to invest $5 billion in Egypt. Similarly, Noble has suspended further drilling plans in Block 12 due to the slashing of its exploration budget.
Resumption of negotiations
The disruption of offshore exploration, which is not expected to resume before 2016 or even 2017, in addition to the expiration of Turkey’s NAVTEX (navigational telex warning) and the withdrawal of its seismic research vessel Barbaros Hayreddin Paşa from Cyprus’ EEZ, opened a window of opportunity to resume negotiations between Greek and Turkish Cypriots. The election of President Mustafa Akıncı — seen as a moderate — in Northern Cyprus on April 26, brought hope, for the first time in years, that the Cyprus problem can actually be settled.
Contacts resumed on May 15. Greek Cypriots would have headed to the negotiation table with a stronger hand had they made a new discovery, which would have made them much more at ease in monetizing their gas resources. Instead, developing the ± 4 tcf Aphrodite gas field is in itself a challenge in the current context. This seems to have brought the Turkish option back to the table as one of the means to monetize Cypriot gas, even faster than negotiators.
Development of Aphrodite
With the break in exploratory drilling, Aphrodite remains the only Cypriot gas discovery to date and will remain so in the short to medium term. Noble Energy is expected to submit its development plan in the next few weeks.
The plan is likely to involve a floating production, storage and offloading (FPSO) unit producing 800 mmcf of gas per day, and subsea pipelines to possible destinations, which in addition to Cyprus may include Egypt. Already, there are difficulties. It appears Noble Energy and Delek, the owners of Aphrodite, are hesitant when it comes to contributing to infrastructure work beyond the development of the field, which would ultimately leave it to the buyers and interested parties to transport the gas to its final destination.
Noble is also obligated to find export markets to proceed with the development of Aphrodite, since the local market is so small (requiring less than one bcm of gas per year) that it does not, on its own, justify development costs. Egypt, with its idle LNG plants and vast local market, emerges as the most logical option. The Egyptian Natural Gas Holding Company (EGAS) is negotiating to import approximately 700 million cubic feet of gas per day from Aphrodite. Gas will be transported via a pipeline that would be completed “within two and a half to three years,” according to a statement by EGAS chairman Khaled Abdel Badie to Daily News Egypt.
But Egypt is setting 2018 as a target year to become self sufficient in gas, and plans to stop imports by 2020. In addition, the Egyptian LNG option also comes with its own sets of challenges, although they can be managed in a way so as to alleviate their impact and make the Egypt option more viable. First, the combined capacity of the two LNG plants in Egypt is 12.2 mtpa and the operators are in discussions with other potential providers, including the Leviathan and Tamar partnerships, BP and BG (for supplies from Egyptian gas fields). This means not all of these suppliers can be accommodated. It is not exclusively a matter of ‘first come, first served’, as other elements such as geopolitics and prices are also taken into account, but timing is very important. Second, there is a risk Cypriot LNG might not be competitive in European markets where LNG is now delivered at around $7 per mmBtu (or even Asian markets, with similar prices). Taking into consideration the price of gas at the well, and adding the costs of transport to Egypt, liquefaction, transportation to Europe, regasification and profits, the end-user price could end up at $12 per mmBtu. Granted, LNG prices regularly fluctuate and cannot be predicted years in advance, but the LNG glut whose impact we are beginning to feel is expected to continue with additional supplies hitting the markets in the next few years, and an expected return to grace for nuclear energy in Asia. Barring a major catastrophe, these developments may indicate that prices are unlikely to return to their all time high in the foreseeable future.
There might still be another option, namely marine transport of compressed natural gas, allowing exports to Europe, although it doesn’t seem to generate much enthusiasm given it is still untested (the first ever carrier currently being designed for Indonesia’s PLN is expected to become operational in May 2016).
Changing market conditions, inflated expectations, a subjective assessment of geopolitics and political risks, unreasonable bets and so on might explain why Cyprus had to abandon grandiose ambitions and make the most out of what it already discovered — in itself significant — all while, rightfully, bracing for more. Unfortunately, these are symptoms we are all too familiar with in Lebanon.