The Middle East LNG story

With 43% of the world’s proven gas reserves, it may come as a surprise that some countries in the Middle East import LNG. Yet, although the Middle East is abundant in natural gas resources, the gas supply and demand balance of each country in the region varies greatly, and in some cases is in a state of transition. A combination of factors, such as under-investment in the upstream gas sector, rapid energy demand growth and high domestic gas consumption levels have prevented the region from being as prolific an exporter of gas as it is with crude oil.

Apart from Qatar (the world’s largest exporter of LNG) and a few other cases (Oman, Yemen and Abu Dhabi), most states in the Middle East prioritise natural gas to meet domestic needs. For some, such as Kuwait and Dubai, LNG is imported to make up for domestic supply shortfalls.

The LNG story in the Middle East is therefore multi-faceted. LNG king Qatar faces a changing landscape in global gas markets with more competitors entering the scene; a new LNG exporting-hub is expected to emerge in the once resource-starved Eastern Mediterranean; and some states are expanding (or introducing) regasification capacity to cope with growing energy demand.

Qatar: king for not much longer

Qatar benefits enormously from a generous endowment of natural gas reserves (885 trillion ft3 and the third-largest in the world behind only Iran and Russia). For a country of only 1.9 million residents (of which only 10 - 20% are Qatari citizens), it is not surprising that its oil and gas export revenue gives it the highest GDP per capita in the world. At the end of the last decade it overtook three Asia-Pacific competitors – Indonesia, Malaysia and Australia – to become the largest LNG exporter. Qatar’s small domestic energy market enables it to primarily target export markets with its gas, although industrial expansion and the start-up of the Pearl gas-to-liquids (GTL) plant should double Qatar’s gas consumption between 2011 and 2018, according to the International Energy Agency. Qatar will still have no problem in supplying gas to export markets – even with its moratorium on further development of the giant offshore North Field – although, like its energy-hungry neighbours, it can curb domestic consumption with better efficiency measures and reducing energy subsidies.

A greater challenge for Qatar, however, is the emergence of new LNG-exporting hubs to meet rising global demand for natural gas. Australia will overtake Qatar as the largest global LNG exporter, with seven LNG plants under construction that will increase its liquefaction capacity from 24.3 million tpy to 85.6 million tpy by the end of this decade. Further capacity additions in Australia will dramatically slow down due to the high cost of constructing liquefaction plants, but Australia will displace Qatar as the prime LNG exporter with projects already under construction.

North America will emerge as an LNG-exporting hub from the end of this decade, especially in the US. Unlike the pricing system used by the most established LNG exporters such as Qatar, US LNG export prices will not be based according to oil indexation. With oil prices high, the price of oil-indexed LNG is also high, but US LNG will be based on the cheaper US Henry Hub spot price. In August, the Henry Hub spot price was trading at around US$ 3.40/million Btu, which compares favourably to the average price of LNG for August delivery in Asia of US$ 15.46/million Btu. Asian LNG buyers are likely to seek LNG volumes from the US to ease reliance on the oil-indexed, long-term contracts that suppliers such as Qatar normally offer. That said, oil-indexation does offer consumers stability in pricing while long-term contracts enable suppliers to make a return on the costly investments in liquefaction capacity. It is unlikely that these facets will disappear from the Asian LNG market altogether, although the prevalence of oil-indexed long-term contracts will be diluted somewhat should there be a splurge of US LNG reaching Asian markets.

To date, three companies have received approval from US authorities to export LNG to countries that do not have a Free Trade Agreement with the US; the total capacity of these projects is approximately 40 million tpy. Canadian authorities have awarded export licenses to three LNG projects with a combined capacity of between 22.9 and 34.9 million tpy. Meanwhile, recent big offshore gas discoveries in East Africa have opened up the opportunity for LNG exports from Mozambique and Tanzania, most likely beginning in the early 2020s.

Despite these evolving trends, Qatar is not hitting the panic button. To date, the country has no plans to expand its liquefaction capacity, or revisit the moratorium on further development of the giant North Field (which has been in place since 2005). Furthermore, in 2012 Qatar continued to sign long-term supply and purchase agreements with Japanese, Korean and Thai customers. The emirate might appear relatively relaxed about its future role as a leading global LNG supplier, but it is likely that in future it will have to be more flexible in contract negotiations with potential customers. One advantage Qatar does have is that the cost of its LNG production is relatively cheap, especially compared to Australia, as well as to what will be supplied by emerging exporters such as Canada and Russia.

In addition to the emergence of new suppliers targeting the Asian market, Qatari officials will also be watching demand-side factors as well, such as the future of Japan’s reliance on nuclear power and how this will impact its LNG requirement, and how successful China will be in developing its own unconventional gas resources as it expands the role of natural gas in its energy mix.

Bounty in the Eastern Mediterranean

Middle East LNG has been focused on the Persian Gulf, but the Eastern Mediterranean has emerged as an exciting new frontier for the industry. Big offshore gas discoveries in Cyprus (Aphrodite) and Israel (Tamar and Leviathan) mean that both countries can develop LNG for export, given the quantity of supply that is expected to be available and the small size of their respective domestic energy markets. An Eastern Mediterranean gas-exporting hub, however, also brings with it some tricky geopolitical issues, given the state of Israel’s relations with its Arab neighbours, and the unresolved dispute between Turkey and Cyprus over the status of the northern part of the island that Turkey has occupied since 1974.

With several offshore gas discoveries, Israel will be able to eliminate the need to import gas and fuel oil for power generation, and reduce usage of (imported) coal in the power sector. In addition, there will be reserves available for export markets, with LNG an option. The Israeli government has reserved 60% of the country’s estimated offshore gas reserves (900 billion m3) for the domestic market, allowing the remaining 40% to be exported. The issue of how Israel’s gas bounty should be used is a contentious one, and the Netanyahu government has adopted an interventionist approach by apportioning the majority of Israel’s gas reserves to meet domestic needs. Originally the Israeli government preferred a 50/50 split in gas reserves between the domestic and export markets, yet even a 40% share for exports would still leave an export quota of 360 billion m3 (260 million t).

Several options are being considered for the export of Israeli gas by Noble Energy and its partners that made the Tamar, Leviathan and other sizeable offshore gas discoveries. These include an onshore liquefaction plant in Israel, a floating LNG facility off the Israeli coastline, and an onshore plant in Cyprus that would be supplied by both Israeli and Cypriot offshore gas fields (Noble Energy also made the Aphrodite discovery in Cypriot waters). Less costly pipeline options have been mooted, such as linking Israeli gas directly to Turkey. Politically, the LNG option would be the most feasible for Israel, provided that the issue over which development option to use is resolved. But liquefaction will also be costly, and Noble Energy and its partners would be disappointed about the imposition of a quota that must be allocated for the domestic market. A domestic supply quota may also complicate efforts to lure potential investors, such as Australia’s Woodside, from partnering with Leviathan’s operators to develop LNG. Furthermore, the Israeli government is reportedly sceptical of plans to build a facility in Cyprus to liquefy Cypriot and Israeli gas, while there are likely to be environmental objections to locating an onshore plant on the densely populated Israeli Mediterranean coast, or at Eilat in the Gulf of Aqaba.

The pipeline option for Israeli gas exports will be cheaper compared to LNG, but it has its hurdles as well, which are mainly geopolitical. Turkey’s relationship with Israel is volatile, and a pipeline through the eastern Mediterranean could arouse objections from Lebanon and Syria. Furthermore, Turkey’s opposition to Cyprus’ oil and gas exploration efforts would make it difficult for Ankara to accept gas from Israel if it engages in energy cooperation with Cyprus itself, such as joint development of Cypriot and Israeli gas fields.

The prospect of Israeli LNG entering the market at some stage is still strong, although to date, which LNG development option to push is undecided. As of early August, Cyprus was reportedly pushing ahead in talks with Noble Energy for the construction of an LNG plant. By the beginning of the next decade, the Eastern Mediterranean will be another source of gas supply for export that will emerge, in addition to East Africa and North America.

The Middle East is an import market too

If you exclude Qatar from the equation, the Arab Middle East will become a net importer of LNG by the end of the decade. This does not seem as ridiculous as it sounds. The Middle East does have plentiful gas reserves, but these are heavily concentrated among three countries: Iran, Qatar, and Saudi Arabia. Qatar is the only one of these that exports gas as LNG, with Iran and Saudi Arabia, due to their sizeable domestic gas markets, unlikely to become LNG exporters anytime soon. Saudi Arabia is prioritising upstream gas investment, but for the domestic market (to replace oil consumption in the power sector), and Iran faces sanction barriers to access the technology to develop LNG capability. Instead, Iran is focusing on regional pipeline export projects to Iraq and Pakistan (it exports pipeline gas to Turkey and Armenia).

This leaves other small Gulf States, which are not as well endowed with natural gas reserves, as well as Jordan, whose reserves of hydrocarbons are negligible. These states, which subsidise electricity prices to keep them cheap, face rapidly growing power generation needs, and in some cases are developing desalination and petrochemical projects. This has led to soaring demand for natural gas, beyond what some of the states can domestically produce. Low domestic prices have also meant that investment in the upstream non-associated gas sector has under-performed, leaving domestic output languishing. Combined with rapid economic growth manifested by high oil prices, and states such as Kuwait suddenly find themselves needing to import natural gas to meet soaring domestic needs. Importing LNG may be expensive, at around US$ 13.45/million Btu, but the high price of oil means that it makes economic sense compared to burning crude oil for power generation; at least in the short to medium term. Rather than burn valuable crude – which can fetch over US$ 100/bbl if it is exported – for domestic power generation, the use of gas for electricity liberates that crude oil for vital export dollars. Using natural gas can also help to develop the industrial base of Persian Gulf economies, e.g. through petrochemicals.

In the short to medium-term, the need for some Persian Gulf states to import LNG will remain. Indeed before the end of the decade, Jordan, Bahrain, and the UAE’s Fujairah will join the ranks of LNG importers, while Kuwait plans to expand regasification capacity. Exporters such as Abu Dhabi and Oman also need to assess the desire to maintain LNG exports in the face of growing domestic requirements for gas. Meanwhile, Egypt, a declining LNG exporter, plans to build LNG import capacity with the construction of a floating storage and regasification unit (FSRU).

In the long run, however, importing LNG may become less viable. As a result, Persian Gulf states can take measures on the demand side to reduce reliance on regasification capacity. These include reducing energy subsidies, improving energy efficiency, developing other energy sources for power generation such as solar, and lifting the industrial price for gas. Prices that reflect market realities would also encourage investment in non-associated gas resources, boosting domestic production. That said, even if states took these measures, a reversal towards a reduction in regional regasification capacity would only be seen in the longer term.

In conclusion, the Middle East LNG story is an evolving one. Qatar will remain a key LNG supplier but will have to watch the emergence of new exporters that will target the Asia-Pacific market, and the Eastern Mediterranean will become a gas-exporting hub as well. In the meantime, other Persian Gulf states will require LNG to meet their growing energy needs, although this can be alleviated with some effective demand-side policies.

Written by Peter Kiernan, The Economist Intelligence Unit, UK. This is a shortened version of an article that features in the September/October issue of LNG Industry. To read the full article, subscribe here.

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