The Mideast's gas paradox
It is home to the world's biggest exporter—and also some of its fastest-growing consumers. Yet intra-regional trade remains thin
The Middle East's transformation from swaggering liquefied natural gas-export hub to insurgent global demand hub continues apace. With domestic demand for gas pushing ever higher, the region's tight band of long-term importing countries—the UAE, Kuwait and Israel—has been expanded in the past couple of years with new entrants Jordan and Egypt. The latter two were among the fastest-growing LNG importing countries last year, amid a rapid deployment of floating storage and regasification units (FSRUs) starting in 2015. FSRUs have enabled the Middle East's new LNG importers to capitalise on fluctuating price trends.
The region's apparently insatiable appetite for spot LNG cargoes has played a large role in absorbing rising supply coming out of Australia. The Oxford Institute of Energy Studies (OIES) notes that the 6% increase in global LNG supply in 2016 was partly attributable to the Middle East's 10bn-cubic-metre increase in demand that year.
In 2017, there is no sign of a slackening of the pace. Middle East LNG imports will rise from 11.1m t/y in 2016 to 13.4m t/y by 2018, according to consultants Energy Aspects, with the Mideast and North Africa (Mena) region poised to add another 1.6m t/y in 2018.
The Middle East's zest for LNG stands in marked contrast to the situation in the early 2000s, when the UAE and Qatar began importing piped gas via Qatar, and Bahrain and Kuwait were also limbering up as potential pipeline offtakers.
A toxic mixture of difficult politics and divergent commercial drivers scuppered ambitious plans to connect more of the region by gas pipeline. That, in turn, has opened up opportunities for LNG.
While Qatar is well positioned geographically to feed gas to demand hungry neighbours, the emirate sees little imperative to prioritise pipeline gas sales around the region at below-market prices.
The result is an unlikely scenario that sees Qatar sending its gas halfway around the world, while its Gulf partners in Kuwait and the UAE draw in cargoes from equally long distances. Kuwait has imported LNG from Sakhalin, for example.
There is some intra-Middle East LNG trade to speak of. Qatar struck a deal in 2016 to supply Kuwait with 0.7bn cm a year of gas for four years. But plans for an integrated Gulf pipeline network have been shelved, with only Oman—planning to import 28m cm/d of Iranian gas via subsea link—still invested in the pipeline game.
Near-term demand growth in the Middle East is weighted towards LNG. Mena countries are set to invest around $10.3bn in LNG-importing facilities over the medium-term to cater for growing demand, predicts Apicorp, an energy investment bank. They will increasingly charter FSRUs as a temporary and lower-cost solution. By the end of 2017, Apicorp sees Mena countries accounting for 6.5% of global LNG demand, compared with just 1% in 2013.
The pace of the region's LNG import increase is impressive. According to the OIES, Middle East LNG demand rose from 5bn cm in 2014 to 24bn cm in 2016.
The demand growth is reflected in the growing number of FSRUs being commissioned. The UAE added one such facility to its existing Dubai import terminal in August 2016, the new Abu Dhabi-based unit boasting capacity of 14m cm/d. The UAE needs to widen its supply sources as it extends gas-fired power generation capacity to reach 17 gigawatts by 2018. Further LNG will come through a planned 9m-t/y import terminal to be located in the country's north.
Elsewhere in the Gulf, Bahrain is looming large as a new LNG import market from 2019. It has opted for an onshore regasification terminal with 4bn cm/y capacity, rather than an FSRU.
Kuwait has a longer track record as LNG importer, and like Bahrain is looking to build permanent import capabilities. Kuwait National Petroleum Corporation awarded construction contracts last year to build a new terminal with a 22m t/y ca-pacity, due for completion in 2021.
Egypt is anticipating brisk LNG demand in 2017. In early February, Bloomberg reported plans to import as many as 108 cargoes of LNG this year. Up to 45 of them will be government-to-government contracts sourced from Oman, Russia and France.
This represents a massive turnaround for Egypt. In 2016, it imported 6m t/y of LNG, making it the eighth largest LNG importer in the world, according to consultancy Wood Mackenzie. In 2009, it was the world's eighth largest LNG exporter.
But Egypt is eyeing a return to LNG-export status. Development of the Zohr gasfield could make Egypt self-sufficient in gas as early as 2019, says the government, freeing up Egypt's FSRUs for other potential customers in the region. It may also reactivate mothballed export plants on the Mediterranean coast, if it can secure the feedstock.
That will hinge on how domestic demand plays out, with around 14GW of new gas-fired power generation capacity currently being installed, and strong latent demand from industrial users and some new investments in the pipeline. Stronger economic growth could soak up some of the potential gas surplus, hampering Cairo's attempts to resume hard-currency-earning LNG exports.
Meanwhile, across the region, some other new LNG buyers are looming on the horizon. Saudi Arabia has mooted the possibility of taking LNG cargoes for the first time, as it seeks to raise the proportion of gas in the domestic energy mix from 50% to 70%. "FSRUs would make sense for Saudi Arabia and enable them to switch gas for oil in power generation," says a Middle Eastern gas analyst. "The problem is that they don't quite trust neighbouring countries like Qatar and certainly don't view them as reliable LNG suppliers."
That represents in microcosm the region's energy dilemma. Flinty intra-regional relations go a long way to explaining why the Middle East's LNG powerhouse, Qatar, will continue to export cargoes of gas halfway across the globe, while its neighbours a few miles away spend money buying in LNG from equally distant producers.
Promise and problems in the East Med
The Eastern Mediterranean has emerged as one of the world's most exciting gas provinces in recent years, but firm liquefied natural gas export prospects are still murky. That is down to difficulties in pinning down buyers for cargoes, the lower prices prevailing in target markets like Europe, and the possibility that favourable political developments could render pipeline export options more bankable—such as a bid by Israel to send gas to Turkey through a subsea link.
Israel also entertains long-term ambitions to join the LNG-export hub. In February 2017, Delek and Noble Energy approved a plan to allocate $3.75bn to develop the Leviathan offshore gas reservoir, in anticipation of first production in 2019. The Leviathan partners are in negotiations to sell gas to Turkey or to Shell's LNG plant at Idku in Egypt.
Idku may also receive Cypriot gas supplies from the Aphrodite field for re-export as LNG, should Nicosia decide against building an expensive LNG-export terminal to deliver cargoes direct to Europe.
Another option would be for Cyprus or Israel to go for FLNG as an alternative to land-based terminals. Given the tricky territorial issues in the East Med, FLNG's flexibility may have strong appeal.
Cyprus is set to be a hive of drilling activity in 2017, with Total planning to proceed with a campaign in Block 11 in April. This reflects international oil companies' piqued interest in East Med gas, following Eni's giant offshore Egypt discovery at the 30-trillion-cubic-foot Zohr field in 2015.
Zohr is the key to unlocking Egypt's bid to reclaim its former mantle as the East Med's largest LNG exporter. Egypt's Egas is looking to boost gas production within the country, from 55bn cm a year in 2017 to 70bn cm/y by 2018, as Zohr volumes come on stream.
If that paves the way for Egypt to (re) start exporting LNG in large volumes by 2020, it will spell bad news for regional rivals with ambitions to export their own cargoes. The competitive pursuit of national LNG targets ultimately may have to take a back seat. Eni, Zohr's developer, has spoken of plans to remodel Egypt as a regional LNG-export hub connecting Cyprus, Israel and possibly Libya.
A pooling of resources—with Leviathan and Aphrodite combined holding as much as 25bn cm/y in export capacity—would create a potentially formidable global gas nexus. It would ensure that Idku and Damietta would never again stand idle. But getting the fractious likes of Egypt, Israel, Cyprus, Turkey, Libya and Lebanon to forge a common approach to LNG exports still looks a distant prospect in 2017.
Can Algeria win back old markets?
State-owned Sonatrach is battling to staunch the slide in its LNG exports to Europe, even though pipeline sales have held up relatively well. The company is anticipating total gas exports for 2017 will reach 57bn cubic metres, up by 3bn cm on 2016. Algeria's gas sales are more heavily weighted to piped gas; only 17bn cm of this will be exported as LNG. That represents a slight increase on the 2016 figure of 15bn cm, after the two-month force majeure at the Skikda LNG plant at a crucial period in the marketing season. About 80% of Algeria's LNG cargoes are sent to Europe, but its market share is under pressure there. Sonatrach has a job on its hands to fend off rivals. Qatar's steady inroads into this market could be followed by US LNG cargoes.
There is, though, still a window of opportunity for Algeria to win back market share. The country will see many of its long-term export contracts end in the 2019-21 period, says Apicorp, a Saudi-based bank. It points out that European countries such as Spain and Italy have many underutilised regasification terminals, and intend to diversify their sources of supply to reduce their dependence on Russian gas. The incentive for Algiers to reinforce its credentials as a stable supplier is therefore strong.
Given Algeria's own underutilised export facilities, Apicorp notes, this would normally provide Sonatrach with a good opportunity to negotiate favourably over long-term contracts. Indeed, Algeria is reviewing its terms with the intention of using a mix of spot and long-term contracts to get the best deals, according to Sonatrach's chief executive Amine Mazouki. Term times may be cut from typical 20-25 year terms to 10-15 years. The aim to solidify a position both in the spot and term markets. The next couple of years will go some way to determining whether Algeria is up to the task.
Battling to retain market share: Algeria's LNG export infrastructure Source: Petroleum Economist
This article is part of a report series on LNG. Next article: Australia battered but unbowed