Having seen little investment in new generation capacity over the past decade, Mongolia is now forging ahead with upgrades to its coal-fired heat and power (CHP) capacity and trying to lure private investment to greenfield plants. Given a looming power shortage, which the Ministry of Energy (MoE) projects at 250 MW by 2016 but the IMF estimates at 600 MW, plus the cap on Russian imports, time is of the essence. The first wind-driven independent power producer (IPP) added a little capacity in mid-2013, and upgrades will come on-line in the next two years. Yet movement on new privately funded capacity – in coal-fired, hydroelectric, wind and solar – is urgent if Mongolia is to curb the increasing black-outs it saw on the central grid in 2013.
With CHP1 already decommissioned, state-funded upgrades are focused on retrofitting three of the central grid’s main suppliers: the 148-MW CHP3, built in 1968 and operating at about 38% efficiency; the 480-MW CHP4, built in 1983 and running at 40%; and the 48-MW Darkhan CHP, built in 1968 and humming at 91%. “The three major upgrades should be completed in 2014,” L. Erdenedalai, president and CEO of Monenergy, an energy consultancy, told OBG. Besides adding capacity, the MoE says these upgrades will extend the CHPs’ lives to 2030 or beyond.
The biggest upgrade is to CHP4. German development bank KfW is funding efficiency upgrades on the plant’s six Russian-built turbines and making room for a seventh that will add 100 MW of capacity, by means of a ¥4.2bn ($40m) soft loan from the Japan Bank for International Cooperation. In parallel, CHP3’s eight Russian turbines are receiving maintenance and a ninth (Chinese-built) one will add 50 MW to capacity. Finally, a fifth, 35-MW turbine is being added to the Darkhan CHP with €15m ($11.2m) from KfW and €5m ($3.7m) from the Mongolian government.
There has also been talk of revamping the 21.5-MW CHP2, built in 1961 and operating at 41.5% capacity, to allow it to use coal briquettes, though a final decision was still pending as of end-2013. On the eastern grid, an upgrade is expected on the 36-MW Dornod plant in Choibalsan in 2015. Plans by the State Property Committee for a 100- to 200-MW privately funded plant are still undergoing feasibility studies.
While such upgrades will add needed capacity, private investors are concerned about the slow progress of public-private partnerships (PPPs). “The long and delayed process of agreeing on the terms of the concession arrangement, tariffs and land allocation for new power plants on the government side, suggest that the government is not aware of opportunity costs associated with postponing of these critical power sector investments,” Ts. Tumentsogt, the GE’s chief representative in Mongolia, told OBG.
Encouraging progress has at least been made in wind power. The 31-turbine Salkhit wind farm, on 12,000 ha 75 km south of Ulaanbaatar, came on-line in June 2013 at 52 MW. The project was developed by a private consortium of Newcom, the European Bank for Reconstruction and Development, Dutch development bank FMO and GE (in a 51:14:14:21 split) and built by Leighton Contractors at a cost of $122m. Four more are planned. “The renewable energy projects like wind farms are politically bold steps, since coal-powered plants are far cheaper. It shows political will to develop cleaner energy sources,” GE’s Tumentsogt told OBG.
Authorities see environmental protection as worth the higher cost of power. Newcom expects Salkhit to reduce CO2 emissions by 180,000 tonnes, and save 150,000 tonnes of coal and 1.6m tonnes of water a year.
The downside is that wind farms make it harder to balance the grid, given their higher cost and fluctuating output. The project has an option to expand capacity to 150 MW when its power purchase agreement (PPA) is renewed – its 1.6-MW turbines can be upgraded to as much as 7 MW each – but this will depend on the readiness of backup capacity provided by CHP4, and on timely payments under the PPA (see overview).
New Wind Farms
By late 2013, four more wind farm projects had signed PPAs with the Energy Regulatory Commission (ERC), and were at varying stages of feasibility study. Privately held CleanTech plans to develop a 250-MW wind-power operation in the Umnugobi Province near the Oyu Tolgoi (OT) and Tavan Tolgoi (TT) mines. Having signed a PPA that could supply both mines plus (through a 220-KV line) the central grid, the developer is working on financial close. “Even if the TT power plant moves swiftly on approvals and financial close, it would still take four to five years to commission, while some wind park projects in the pipeline may come on-line in two years since they already have off-take agreements in place,” GE’s Tumentsogt told OBG.
A second project for a 52-MW farm in Sainshand also holds a PPA at $0.095 per KWh. A joint venture between EuroKhan and Germany’s Ferrostaal was working on financing it in 2013, expecting to maintain a majority stake and to break ground in mid-2014. A third project, a 50-MW farm in Choyr backed by Turkish firm Aydiner, broke ground in 2013, though work had reportedly stalled by end-2013. The fourth PPA, for a 100-MW farm, was awarded in 2011 to AB Solar Wind, which was negotiating financing in 2013.
Meanwhile, Newcom is involved in a second wind farm project. Its joint venture with Japan’s SoftBank, called Clean Energy Asia, is to develop a 200- to 300-MW farm on 200,000 ha in the south Gobi. Resources are still being evaluated and PPA negotiations pending, but potential off-takers for the power include the central grid or a proposed Asian super-grid backed by Softbank. With such inconstant potential sources of energy, the central grid will need loads of backup capacity, which only coal-fired or large hydro-electric plants can offer.
Central to government efforts to close the energy gap is the delayed 25-year build-operate-transfer concession for CHP5, which is meant to produce 450 MW of power and 587 MW of steam. Cast as a replacement for CHP3’s low-pressure unit, the Ulaanbaatar local government in 2012 prompted its relocation outside the city, eventually settling on a 85 ha plot south-east of Ulaanbaatar. “While our feasibility study on CHP5 estimated the cost at around $700m under a ‘scrap-and-build’ model on the CHP3 site, the new PPP model outside the capital will cost twice that, around $1.2bn-1.4bn. The government will need to build all of the associated infrastructure,” Monenergy’s Erdenedalai told OBG. This cost far outstrips the average for coal-fired plants, about $1.4m per MW.
To muddle matters further, the authority to form PPPs shifted from the State Property Committee to the new Ministry of Economic Development (MED) after the June 2012 elections. This prompted a cancellation of the previous tender, which in July 2011 had selected a consortium of GDF Suez, Japane’s Sojitz, Korea’s POSCO Energy and Newcom in a 30:30:30:10 split. In August 2013 the group was once more confirmed as preferred bidder, but the project will now require a new feasibility study and environmental impact assessment before proceeding to financial close.
The economics of the project are a concern. With a PPA at MNT63 ($0.038) per KWh, the consortium, to be profitable, would need coal at concessional rates similar to state-owned power plants, which at MNT18,000 ($10.80) a tonne are below production costs. Construction is likely to take at least three years, meaning CHP5 would come on-line in 2018 at the earliest.
One alternative could be the 4×150-MW mine-mouth power plant backed by Canada’s Prophecy Coal on its 124m-tonne Changdana coal mine at a cost of $800m. Having finalised all other permits, Prophecy was still awaiting a delayed PPA at end-2013, a precondition for concluding project finance. Since it is only about 200 km from OT, the plant could conceivably also supply that project through a 220-KV line when OT’s Chinese supply agreement expires at end-2016.
The government seems intent on proceeding with a planned 3×150-MW concession to use thermal coal from TT’s power plant, ETT, to produce electricity for both mines, which are 130 km apart. In October 2013, the MED pre-qualified four bidders – Marubeni, Daewoo E&C, Kansai Electric Power, and a joint bid by GDF Suez and POSC – providing an initial $50m to cover a feasibility study, an environmental impact assessment and a government stake of 2% out of a total projected cost of $1bn. (MCS will own a 30% stake, and these competitors are bidding on the remaining 68%.) Though linked to the grid, the plant would send most of its power to OT, which has projected needs of 310 MW, and to TT. A host of other coal-mine-mouth power plants are in feasibility-study stages, and a long-standing project to build a 220-MW hydroelectric dam on the Egiin river appeared to be gaining traction in late 2013. The MED announced allocations of $50m to the project, with bidder pre-qualification expected in 2014.
While the planning for such large-scale, stable generating capacity will continue, the short-term boost to capacity will come from wind farms. Upgrades to the central grid will help close the supply gap, yet much more greenfield capacity is needed. Given the long lead times of large-scale projects, most planned power will not come on-line until 2018. Mongolia will therefore find it a challenge to meet demand in the next four years.