Despite abundant reserves of fossil fuels and potential renewable energy resources, Mongolia has lagged in developing new power supply to match surging demand. Domestic electricity demand has grown by 30% to 5.5m KWh between 2008 and early 2014, but supply has grown by only 6.8%, with the balance imported from Russia. A key explanation is the long gestation period for privately financed power projects.
While successive governments have been committed to the model of independent power plants (IPPs), the Mongolian process of public-private partnerships is unique and can cause delays: investors sign a framework concession with the government before finalising key aspects of the financial package, including details of the power purchase agreement (PPA), coal supplies and funding terms.
The only greenfield power plants coming on-line between 2013 and 2016 are in wind, for which fluctuating output and high prices relative to conventional sources will exacerbate strains on the grid. Much-needed rehabilitation of combined heat and power plants (CHP) 3 and 4 are key to ensuring adequate supply until 2016, while a new heat-only plant in Ulaanbaatar will provide steam to the city’s eastern enclave. Yet over the long term, development of long-awaited IPPs like CHP 5 in Ulaanbaatar and the Tavan Tolgoi Power Plant (TTPP), alongside a handful of planned coal mine-mouth plants, will be key to Mongolia’s energy security.
Wind Gusts
The 2007 Renewable Energy Law and concessions in 2010 set a high feed-in tariff for renewables such as solar and wind to attain the ambitious target of 20-25% of the energy mix by 2020. The first large-scale wind farm at Salkhit, 75 km from Ulaanbaatar, secured a $0.09 per KWh tariff under its 20-year PPA with the Ministry of Energy (MoE) – much higher than the average MNT65 ($0.04) per KWh charged by state-owned CHPs. Backed by Newcom (51%), the European Bank for Reconstruction and Development (14%), Dutch development bank FMO (14%) and General Electric (21%), the 50-MW farm was developed at a cost of $122m on 12,000 ha and began supplying the central grid in June 2013. Yet while its installed capacity is 168.5m KWh per year, enough to supply 100,000 households, the mismatch between peak load and peak demand means the grid operator can only rely on an effective 60% of its capacity.
The project holds an option to double capacity to between 100 MW and 150 MW upon the PPA’s expiring in 20 years, by replacing the current 1.6-MW turbines with 7 MW. This will depend on the government’s appetite for high-priced electricity and its respect for the take-or-pay terms of the PPA.
Despite these teething problems, which the ministry hopes to address by encouraging industries to operate at night, several wind farms with a combined 511 MW of capacity had signed PPAs by 2013. The most advanced is a project backed by Clean Energy Asia – a joint venture between Newcom and Japan’s Softbank – and Swedish investment fund Happy Wind near Tavan Tolgoi (TT), for a 250-MW farm in two tranches. The first 102-MW phase worth $200m has received all permits and is set to start construction in 2016. Clean Energy also received a five-year concession to build a 50-MW farm in southern Tsogttsetsii in October 2014. Other key projects include: a 52-MW farm in Sainshand for $120m by Germany’s Ferrostaal Industrial Projects, due to come on-line by early 2016; a 50-MW farm in Choir for $95m by Turkey’s Aydıner; and another 100-MW project in Choir by AB Solar Wind.
“Mongolia has significant potential in terms of wind-based power generation. If you look at wind maps of Asia, the Gobi Desert and Tibetan Plateau are the windiest places,” J. Bolor, CEO of Newcom Group, told OBG.
Interim Measures
Conscious of the need for more reliable large-scale sources of renewables to meet its goals, the government is offering build-operate-transfer (BOT) concessions for a number of hydroelectric dams. The first of these will only come on-line in 2017 at the earliest, however. “With more wind farms coming on-line, we will be exposed to more fluctuations in power supply, given volatile wind resources,” B. Ganbat, the head of dispatching at the National Dispatching Centre, told OBG. “We will have to use Russian imports and CHP 4 output to balance the grid, although this will place further pressure on CHP 4.” Refurbishments to Ulaanbaatar’s two main ageing power plants, CHP 3 and CHP 4, in 2014 have been essential to strengthening the central grid, adding a combined 170 MW and extending their lives beyond 2030.
Upgrades to CHP 3 were first completed in July 2014, with a ninth Chinese turbine adding 50 MW of power and 75 kcal of heat. Germany’s KfW is funding the refurbishment of CHP 4’s six existing Russian-made turbines, adding roughly 120 MW of capacity, while a $40m loan from Japan’s Bank for International Cooperation is funding a new 100-MW turbine. Although the upgrades have caused some interruptions at CHP 4, their completion will add 120 MW of electricity and 188 kcal of heat to the grid. The MoE is also completing smaller upgrades, by installing new boilers at CHP 2 to maintain its 21.5-MW output and through a fifth, 35-MW turbine at the Darkhan CHP, co-funded by KfW with €15m and €5m from Mongolia’s budget. The MoE has also planned refurbishment for the 36-MW CHP in Dornod in 2015 to maintain output.
The single largest project is a 20-year BOT concession that was signed in April 2013 with the China Machinery Engineering Corporation to build a $75.9m, heat-only thermal plant to supply 388 MW used to heat 50,000 households in Amgalan, in eastern Ulaanbaatar. The new thermal plant will replace 86 low-pressure stoves in the capital’s Bayanzurkh district, which had distributed CHP 4 heat at high losses.
Coal-Fired Power
While such upgrades are key to Ulaanbaatar’s electricity and heat security in the short term, the government is seeking to expedite two long-delayed coal-fired projects to meet the needs of the central grid and large mines in the south. The largest, CHP 5 in Ulaanbaatar, will be developed under a 25-year BOT concession, signed for the $1.34bn project in June 2014. A consortium of GDF Suez (30%), Japan’s Sojitz (30%), South Korea’s Posco Energy (30%) and Newcom (10%) was first retained as the preferred bidder in July 2011 and again in August 2013, before finally concluding the concession in June 2014.
Yet while the concession is in place, other contracts like the PPA, coal supply agreements, land use contract, water supply and the funding package are still awaiting confirmation. Structured in a healthy 30:70 equity-debt split, the consortium expects to reach financial close on its $975m debt package by early 2016 in order to open the three units in 2020, producing 450 MW of electricity and 505 Gcal per hour of heat combined. Yet as of early 2015 the terms of the PPA had not been set as environmental and social impact assessments were still being carried out.
Like CHP 3 and 4, CHP 5 will draw the majority of its coal supplies from Baganuur and Shivee Ovoo, both of which are expanding output. If a tariff of around MNT65 ($0.04) per KWh were set for the PPA, however, purchases from state-owned coal mines would need to be equally low, at MNT18,000 ($10.80) per tonne in order for the project to remain profitable.
Another Major Project
The CHP 5 project may also act as a way for the consortium to increase its chances for securing the attractive TTPP development. Under its 2009 investment agreement, Rio Tinto’s Oyu Tolgoi (OT) is required to develop a local power supply for its mining operations. Although a four-year exemption allows the company to import roughly 200 MW of electricity for the first phase from China’s Inner Mongolia Power, OT will require a domestic source in 2017, particularly once the second phase is agreed upon.
Rio Tinto signed a cooperation agreement with the MoE in August 2014 to develop local power supply within four years. Some 150 km away from OT, the massive TT deposit holds some 7.42bn tonnes of coal, and successive governments have sought to concession out mining at TT – and linked the power plant to the concession – but have made little progress.
While state-owned Erdenes Tavan Tolgoi (ETT) started mining TT’s West Tsankhi deposit in 2013, its thermal coal was left unsold. However, the TTPP project would create significant demand for coal and the 450-MW project has attracted much attention.
The government provided $50m as a seed investment, and in October 2013 four bidders were pre-qualified: Marubeni, Daewoo E&C, Kansai Electric Power, and a consortium of GDF Suez and Posco Energy. The project includes three 150-MW turbines to be completed by 2017. While the government will not have any equity in the project, MCS is entitled to be a minority local partner. The firm’s affiliate, Energy Resources, operates Mongolia’s only hard-coking coal washing plant at TT’s Ukhaa Khudag mine. The $650m plant will provide an outlet for around 1m tonnes per year of ETT’s thermal coal, but could also buy fuel from the smaller private TT mines. While most of the output will be sold to OT, the TTPP would also supply the excess along a 220-KV line to the southern and central grids. With so many new plants, Mongolia is on its way to energy security.
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