First deliveries of “Mongol93” hit the market in May 2013. With its plans to build a domestic refinery delayed, Mongolia has agreed to swap crude for refined fuel with PetroChina, a subsidiary of China National Offshore Oil Corp. This new import source, though still expensive, should reduce Rosneft’s leverage at the trading table. Even a domestic refinery, however, would still rely on imports of Russian crude. In the long term, only the development of expensive coal-to-liquid (CTL) plants would move Mongolia towards self-reliance.
As Mongolia’s oil production steadily increases – rising from 2.2m barrels in 2010 to 5.1m in 2013 and set for 7.1m by 2017, according to the Petroleum Authority of Mongolia (PAM) – authorities are seeking better terms on imported fuel. Under the March 2013 agreement, PAM will trade 70,098 barrels of crude a month for the same amount in Euro-3-compliant petrol (named Mongol93 after the Khukh-Khot refinery in Inner Mongolia). From May 2013, imports of lower-grade Euro-2 from Rosneft (called AI92) receive a discount of $100-150. During the prime minister’s visit to China that October, plans were announced to boost imports to 35, 000-40,000 tonnes a month once import infrastructure is upgraded. Crucial to this is an upgrade of the ZamynUud/Erenhot fuel trans-shipment depot from 6000 cu metres to 16,000, which the Mongolian government is undertaking at a cost of $4m and is due to finish in 2014. Chinese imports, handled by Shunkhlai, Magnai Trade and NIC (a subsidiary of Petrovis), have already multiplied Mongolia’s sources. Russia’s share of imports dropped from 99.1% in 2010 to 76.5% in the first 11 months of 2013, according to PAM, while China’s rose from 0.9% to 5.1%. The balance is supplied by Belarus (9.3% in the year to November 2013), South Korea (7.2%), Lithuania (0.8%), Malaysia (0.5%), Latvia (0.3%) and Singapore (0.2%), according to PAM.
As an interim measure, the government is keen to develop mid-stream processing. A key plank of its four-year Action Plan to 2016 is to build a refinery in Darkhan, designed to process 2m tonnes of crude a year – more than Mongolia’s 1.1m-tonne consumption in 2012. A feasibility study by Japan’s Marubeni and Toyo Engineering in November 2013 involves a public-private partnership of Petrovis, MT and Just Oil, named Darkhan Oil Refinery. Pending parliamentary approval, construction is to start in 2014, but as of late 2013 the economics were still unclear. The refinery is meant to handle a blend of 60% imports from Russian Transneft’s Eastern Siberia-Pacific Ocean and 40% Mongolian crude. Yet though Darkhan was chosen for being near to the Russian border, the pipelines linking producing fields in eastern Mongolia will add to the refinery’s cost, conservatively budgeted at $600m.
Coal – Lateral
The long-term plan is to build CTL plants to use Mongolia’s abundant reserves of coal. Three projects have been mooted so far: Mongolyn Alt (MAK) has plans for two such plants – one at Choibalsan using brown coal reserves to produce 93-benzine, and one at its flagship Naryn Sukhait in south Gobi to produce diesel for trucks catering to southern mining projects. MCS, meanwhile, formed a joint venture with South Korea’s POSCO to develop one near its Baganuur mine to produce 100,000 tonnes of dimethyl ether (cheaper and cleaner than liquefied petroleum gas) and 450,000 tonnes of diesel a year. As of December 2013, MAK’s feasibility study was approved by government, but the other two were still pending. Coal to gas is a fourth option: in October 2013, the Ministry of Mining signed a loose memorandum of understanding with Sinopec to develop a $1bn brown coal gasification plant that would transform 50m tonnes of coal into 15bn tonnes of gas fuel a year. While such processes are expensive – the start-up cost for one CTL plant is more than $3bn – the high price Mongolia pays for imports could render the project feasible (the MAK study found that the Choibalsan site would halve the current retail price). For any of these projects, though, lead times are long – usually two to three years following regulatory approval, making domestic refining unlikely until 2017.