Energy security was never going to be easy for a country as big as Iran but with only about 3m people. Despite abundant reserves of coal and rich potential for wind, solar and hydroelectric power, Mongolia has lagged in exploiting its natural resources. From generation to transmission to distribution, its power infrastructure is outdated, and reliance on foreign imports is growing. Aware of this, the government has been pushing to fast-track a batch of projects that, if successful, should reduce the country’s dependence on any one supplier, and may in time sprout an industry in its own right.
Three things the state is now doing could further this. First, it is forging ahead with plans to upgrade its power transmission and distribution network, and trying to attract private investment to greenfield plants. Second, it is gradually liberalising power tariffs, which could help reduce costs for end-users. Third, it is planning new laws to spur exploration in crude oil. The output growth that should result could eventually be put towards building a domestic refinery. While such ambitions are bound to take time, authorities have made visible progress in diversifying sources of fuel imports, and this may, over time, improve Mongolia’s terms of trade.
Mongolia faces a growing inability to meet domestic demand for electricity. Its power infrastructure, much of it built by the Soviets in the 1960s to 1980s, consists of five grids, three loosely interconnected and two isolated. The first, the central energy system (CES), covers 80% of the population and accounts for 90% of installed capacity and 96% of power consumed, according to the Ministry of Energy (MoE). It supplies 13 provinces from five coal-fired combined heat and power (CHP) plants. These have a total generation capacity of 714.3 MW, though they produced only 647 MW in 2012 given their low efficiency, according to the Energy Regulatory Commission (ERC). Three other plants are located in the capital city: CHP2, built in 1961, provided 9 MW in 2012 (of its 21.5 MW capacity); CHP3 produced 109 MW (of 136 MW); and CHP4 generated 458 MW (of 480 MW). Only one new source has been added to the CES in two decades: the 52-MW Salkhit wind farm, which came on-line in June 2013.
The other two main grids are more diverse. The eastern energy system (EES) draws power from a 36-MW coal-fired plant in Choibalsan, the capital of Mongolia’s easternmost province of Dornod. Output from this unit was 29.5 MW in 2012. The western energy system (WES), meanwhile, is supplied from power imports from Russia, which sends about 10 MW through a 110-KV transmission line. Sources here include small-scale hydroelectric units during the seven months a year when rivers are unfrozen, such as the 11-MW Durgun hydropower plant (HPP) in operation since 2008.
Remoter areas draw on yet other sources. The AltaiUliastai energy system (AUES), located between the CES and WES, supplies the Zhavkhan and Gobi-Altai Provinces, drawing from the 12-MW Taishir HPP since 2011. Diesel generators and small-scale wind and solar energy systems have since been added. The southern electrical system (SES), in turn, consists of a small grid centred on the southern capital of Dalanzagdad in Umnugobi. It was expanded in 2012 with a 110-KV line to Tsogttsetsii (near the Tavan Tolgoi coal mine, or TT) and a 220-KV line joining it to the CES. Small towns near the Chinese border are supplied by imports from a 6-MW CHP plant built by Hyundai in 2001, while the newly commissioned Oyu Tolgoi (OT) copper and gold mine, which is on the SES grid, imports roughly 200 MW of electricity from China’s Inner Mongolia Power, under a four-year contract running to the end of 2016.
The biggest power source in Mongolia is coal-fired thermal plants. But the mix is changing. The share coming from coal fell from 91.4% in 2012 to 75% in 2013, while that from renewables grew from 0.1% to 7% after the Salkhit wind farm was commissioned and came on-stream, according to the MoE. Hydro-dams provided 1.2% in 2013, diesel generators 1% (up from 0.48% in 2012) and Russian imports plugged the gap with 17%.
A Growing Gap
The grids have not kept up with peak demand. According to ERC figures, their total installed capacity reached 813 MW in 2012, while peak demand hit 960 MW, up from 729 MW in 2010. Power consumption grew 6% on average in the four years from 2007, according to German development agency GiZ. The chief causes of this are rural-urban migration, industrial development and mines – the last of these accounting for 40% of consumption. The National Dispatching Centre (NDC), the spot market operator, estimates that demand for power grew 9.5-10% in 2013, and expects it to double by 2025. The Asian Development Bank forecasts even more: 3 GW by 2030. Demand would likely grow even faster were Mongolia’s distribution capacity upgraded at a swifter pace. The Ulaanbaatar Electricity Distribution Network Company (UBEDC) was forced to turn down 1000 requests for connections in 2012, mostly from newly arrived migrants. The gap between supply and demand has been widening since 2012, when the first blackouts began on the CES.
Russian imports have made up the balance, accounting for 7.6% of consumption in 2012 and 17% in 2013, according to the MoE. Under contracts negotiated yearly and priced in roubles, Mongolia imported 175 MW in 2013 through a 220-KV interconnection to the Russian grid, and will buy 210 MW in 2014. By 2016, the IMF forecasts a shortfall of 600 MW, though the MoE expects a smaller one of 250 MW, citing greenfield plants and upgrades to CHPs.
Although this growing gap will likely require more Russian imports, the government has as yet no plans to upgrade the current 220-KV Russian interconnection to handle higher loads. “The government strategy is not to expand capacity for electricity imports, but rather to develop domestic generation,” Ganbat Baatar, the NDC’s head of dispatching, told OBG (see analysis).
The power sector was unbundled under the 2001 Energy Law, which established 18 joint-stock firms under the state property committee. This list includes five in the generation segment, which operate thermal plants; the National Electricity Transmission Grid Co (NETCO), which operates the grid; the NDC, which operates under a single-buyer model; 10 distribution companies covering regions of Ulaanbaatar, Darkhan-Selenge, Erdenet-Bulgan, Baganuur and the south-eastern region; and district heating companies in Ulaanbaatar and Darkhan. A new distribution company was established to manage the SES in 2013 in southern Dalanzagdad, but only the Darkhan distribution operator was successfully privatised, in 2005.
Indeed, it remains an open question whether private competition could even succeed on grids dominated by single plants. “The track record of privatisation of energy companies, including the privatisation of Baganuur heat only boiler through a management agreement, suggests that private companies need to improve their operational and management capabilities,” Ts. Tumentsogt, GE’s chief representative in Mongolia, told OBG. However, the 2007 Renewable Energy Law and the 2010 Concession Law, did create frameworks for privately developed power plants.
Potential In Renewables
The 2007 law set parameters for feed-in tariffs on renewables like wind, solar and hydro, as well as for off-grid systems. The exact rate, however, is fixed by power purchase agreements (PPAs) negotiated with the ERC. The ambition is for renewables to reach 20-25% of the energy mix by 2020.
The country’s scope for renewables is vast. For solar energy, it has an average potential of 1400 KWh per sq metre per year, up to 300 days of sun and 4.3-4.7 KWh per sq metre per day of solar intensity, according to the MoE. Its 1100 GW of wind-power potential – more than China’s for wind and solar combined – is especially concentrated in the sparsely inhabited south Gobi. Meanwhile, the country’s 3800-odd rivers could support a hydropower stream of 6417 MW and produce 56.2bn KWh of electricity a year.
Installed renewable generation is just a fraction of this. Mongolia has 28 MW of hydroelectric capacity; 12 small-scale renewable (wind and solar) energy systems producing 60-150 KW in district centres; more than 60 MW of wind power; and roughly 1 MW of on-grid solar generation. In another area, the 2009 Nuclear Energy Law contains plans to develop nuclear power, leveraging the country’s uranium reserves, but this goal remains long term (see Mining chapter). Wind farm projects hold more immediate promise: five PPAs in this area had been awarded by end-2013 (see analysis). Raising the share of renewables to such ambitious levels faces high hurdles, not only in matching fluctuating loads to meet demand, but also in handling the high feed-in tariffs planned in the system’s working cost-recovery model.
A key challenge to further liberalisation lies in the implicit subsidies or “non-commercial returns” embedded in the operations of state-run power plants. Though the 2011 amendment to the 2001 Energy Law calls for retail power tariffs to be increased gradually to cost-recovery levels by 2015, current pricing structures imply high government subsidies, on two levels.
First, existing tariffs on generation for Mongolia’s CHPs are well below cost-recovery levels. CHP4 sells power to the grid at MNT40 ($0.024) per KWh; CHP2, CHP3 and Darkhan at MNT60 ($0.036); and the Erdenet plant at MNT90 ($0.054). Even the highest of these is far lower than renewables tariffs, which average MNT160 ($0.096), according to the MoE. Imports from Russia, by contrast, cost about MNT110 ($0.066) per KWh in 2013, and those from China are in the MNT160-220 ($0.096-0.132) range (though these fluctuate given their pricing in roubles and renminbi, respectively).
The higher cost of renewables, though justifiable on environmental grounds, increases financial pressures on the grid operators. “Mongolia will need to limit the number of wind farms it develops, especially if it intends to liberalise retail tariffs, since wind generation tariffs are more expensive than Russian imports by roughly MNT40 ($0.024) per KWh,” B. Tsendsuren, director-general of the MoE’s Policy Implementation and Coordination Department, told OBG.
Second, subsidies to the power sector have been recorded on-budget since 2010, with their total set at MNT60bn ($36m) in the 2013 budget. With coal accounting for 40-50% of power-plant operating costs, however, the implicit subsidy for coal purchased from state-owned mines in Baganuur, Shivee Ovoot and Ulan Ovoot reduces the strain on generation companies: the cost paid for coal from these mines, MNT18,000 ($10.80) a tonne, stands below the cost of extraction. Qualified bidders for the planned CHP5 in Ulaanbaatar have proposed PPA prices of MNT64 ($0.0384) per KWh, but it remains unclear at what price coal inputs would be purchased. The government, in the meantime, has pledged to keep thermal coal input prices low for state-run plants. “Fully liberalising thermal coal prices paid by generating plants would have a knock-on effect on retail prices,” Bayarbaatar told OBG. “We plan to keep these coal prices at below $20 a tonne.” Although end-user tariff increases were planned on an annual basis from 2010, they were only implemented in 2011 and 2013, in a two-tiered approach. The latest, in July 2013, saw prices increase by 30% to MNT130 ($0.078) per KWh for mining firms (which account for 40% of national consumption), and by 18.32% for businesses, to MNT88 ($0.053); those for residential users remained flat at MNT79 ($0.047) per KWh for users up to 150 KW and MNT96 ($0.058) for those above.
How fast to raise tariffs is a puzzle. Doing so is the key to cost-recovery, yet it also threatens higher prices for consumers. Double-digit inflation has compounded the problem by weighing on profitability. “Even though inflation largely offset the tariff increases in 2013, this raise shows the government’s willingness to reach full cost-recovery tariffs by the end of 2015,” GE’s Tumentsogt told OBG. “The combined MNT60bn ($36m) losses recorded by the power and coal sectors in 2012 means there is substantial pressure to adjust tariffs.”
Even so, the ministry is realistic about the feasibility of raising prices this fast. “Although parliament has voted to fully liberalise retail electricity prices, this is unlikely to happen by 2015 given its social impact,” Bayarbaatar told OBG. “We will have to proceed in stages.”
“If the government stops energy subsidies, prices will fluctuate for a period of time, but in the long-term they will stabilise and the energy sector will be completely market-dominated,” J. Ochir, general director of Grand Power, told OBG. “This will be beneficial for the sector and for the users in the long run.”
Balance Of Power
Under the 2002 Integrated Power Energy System plan, which runs to 2040, Mongolia aims to invest in its high-voltage DC transmission infrastructure. The intent is to expand interconnections between its separate grids and allow for spot sales nationwide. A number of new links have already been established, including a 220-KV line from South Gobi to the CES, a 110-KV line from Mandalgovi to TT and a 220-KV line from TT to OT. This last would carry power to OT from a power plant at TT, planned over the last two years by MCS Group. “Large mining projects in the south Gobi are driving significant demand for power,” Bayarbaatar told OBG. “So we established four sub-stations and 400 km of associated transmission lines to Choyr, Mandalgovi, TT and OT in 2013.” As of end-2013 all but four soums (districts) are connected to 15- to 25-KV lines. While the goal of an 800-KV line from Irkutsk (in Siberia) to Beijing is still distant, the government is to complete a feasibility study on upgrading the Russia-CES line from 220 KV to 330. Such upgrades would reduce transmission losses.
The bigger problem is losses in distribution. According to UBEDC, these can range from about 1.8% on 3-KV lines up to 40% on some 0.4-KV lines. “The loss ratio on transmission and distribution was 16.3% in 2012, but transmission losses themselves are very low, in the 3-4% range,” Baatar told OBG. “The challenge is distribution.” To meet this, the 2007 Renewables Law aims to reduce total losses to the single digits by 2020.
For their part, distribution companies have focused on rehabilitating sub-stations and distribution lines, and installing more efficient “smart” meters. The largest distributor, UBEDC, with roughly 300,000 clients, is investing a total of MNT11bn ($6.6m) in such projects in coming years. In 2013, it upgraded 37 sub-stations and 120 km of lines in the capital in 2013. “Our priorities are to reduce sub-station load factors and increase transmission-line capacity from 160 KV to 250 KV in an effort to reduce technical losses,” J. Osgonbaatar, vice-director of UBEDC, told OBG. “We are also seeking to roll out more smart meters to reduce commercial losses.” The cost of replacing the last 40,000 old Russian meters in Ulaanbaatar is $5m-6m, UBEDC estimates. District heating networks, however, which feed the older properties in key Mongolian cities, remain highly inefficient. They run continuously from September 15 to May 15, and do not allow in-house regulation of temperatures. As a result, when it gets too hot, many residents simply open their windows.
Balancing the grid is another matter. Since wind and solar levels oscillate, the higher the input from renewables, the harder it is to even out the power load and source enough back-up capacity from coal-fired CHPs. “As renewables like wind are not constant power sources, but fluctuate, Mongolia needs backup capacity to balance the grid,” L. Erdenedalai, Monenergy’s president and CEO, told OBG. “The central grid, for instance, can absorb 75-80 MW of wind power, but above that we need new coal-fired or hydro capacity as backup.”
The scale of this difficulty varies. Obstacles are high for large projects (over 50 MW), while small ones ( 10-12 MW) are more easily handled. At the Salkhit wind farm, for instance, the on-off nature of gusts means the dials must be constantly adjusted. “Around Ulaanbaatar, the peak of wind coincides with the trough of demand, about 10.00am-4.00pm, making it a challenge to distribute the load evenly and balance the grid,” Bayarbaatar told OBG. “So we only count on 30 MW of power from the 50 MW installed at Salkhit.” As new capacity is installed in coming years, channelling streams of renewables should improve (see analysis).
Given Mongolia’s vast yet sparsely populated landmass, the reaches of its power grid are limited. One plan, launched in 1999, aims to solve this by providing portable single-cell solar panels to 100,000 nomadic herders who dwell in ger (felt tents). Half of the $300-500 cost of such equipment is covered by a public subsidy, supported consecutively by Japanese, Chinese and government aid and, from 2006, through the World Bank’s Renewable Energy for Rural Access project. With the help of two $3.5m grants from the World Bank and a $6m one from the Dutch government, the programme saw adoption rise from 5000 solar kits in 2002 to 32,000 by 2005, and hit its target of 101,146 kits by 2013 (albeit two years behind schedule). The World Bank assistance was crucial, helping install a network of 50 distributors nationwide (at least one per province), providing sales and maintenance and accelerating uptake. The project also had healthy knock-on effects, stimulating sales of electrical appliances, from mobile phones to satellite televisions. Under the state’s renewable energy plan, the aim is to reach full electrification by 2020, up from about 65% in 2013.
Fuel Price Stability
Mongolia’s dependence on imports is even more evident in the refined petrol market. Every one of the 1.1m tonnes of fuel Mongolia consumed in 2012 (up from 810,000 in 2010) was imported, and petroleum products account for 20% of the country’s import bill. Though more than 90% of this has historically come from Russia’s state-owned Rosneft (either directly or through traders like Swiss-based Gunvor), a new swap agreement with PetroChina has boosted imports from China (see analysis).
Such diversification matters. Mongolia claims that Russia interrupted supplies in October 2012, and that Rosneft has hiked its prices through higher Russian taxes on fuel exports: A80 petrol went up 2.9%, to $1132 per tonne; A92 by 3.4%, to $1345 per tonne; and diesel by 9.3% to $1061 per tonne. To keep prices stable and hold down the cost of domestic transport, the government has turned to subsidising its fuel importers. Since May 2012 it has granted $120m of loans for the purpose at 3.8%, channelled through commercial lenders by the central bank. Under this policy, some MNT192bn ($115.2m) was disbursed to 11 importers in the year to September 2013, according to the World Bank. The central bank also signed $82.5m worth of two- to six-month forward agreements at discounted foreign-exchange rates, thereby softening the blow to the industry of the depreciating tughrik, whose value fell 25% against the dollar in the first nine months of 2013. (It has since nudged downward even further.) While these measures have provided some domestic price stability in the short run, price rises are likely in 2014. “If the tughrik stays this low, the domestic retail price of fuel will have to rise in 2014,” D. Gansukh, general director of MPI Consultants, which specialises in downstream, told OBG “It is inevitable.”
Though the retail market is fragmented (17 importers were registered in early 2013), four large firms dominate. The largest, Petrovis, acquired 80% of the privatised NIC in 2004 and now commands about 40% of the market, with more than 300 petrol stations nationwide. The second largest, Magnai Trade (MT), with about 120 stations, acquired Just Oil in July 2013 for around $50m after Russian-owned Just Group went bankrupt, although the deal was still awaiting regulatory approval in late 2013. “Even if MT’s acquisition of Just Oil’s assets is allowed to proceed, the combined entity would operate only around 150 stations, roughly half the number run by Petrovis,” Gansukh told OBG. The other two main retailers, Shunkhlai and Sod Mongol, are roughly the same size.
Authorities’ attempts to hold down prices in 2013 have slowed investments by market players. “The government’s subsidising of fuel importers is not working, since the funds budgeted are insufficient to cover demand in 2013,” Gansukh told OBG. “Thus fuel importers have not been able to implement their investment plans this year.” Nonetheless, limited investments in new fuel depots in secondary towns have taken place. Petrovis built new depots in north-west Ulaangom and east Dornod; the Chinese put up new warehouses in Choyr and Sainshand. The largest investment under way, though, is the government’s $4m project to almost triple – to 16,000 cu metres – the capacity of its transshipment and storage depot at the Zamyn Uud–Erenhot border crossing to China (see analysis).
Mongolia’s potential as an oil producer, in both conventional crude and (in the longer term) oil shale, could eventually close the supply-demand gap. After shallow exploration and limited production by the Soviets in the 1950s and 1960s, Mongolia became a small-scale oil exporter in 1998. Its regulator, the Petroleum Authority of Mongolia (PAM), opened exploration rights in 1991 and now has 30 blocks – 20 awarded as production-sharing contracts (PSCs), two open to tender and eight under PSC negotiation as of end-2013. Early exploration in Dornod in the 1990s by Western firms was taken over by Chinese operators in 2000. Today two Chinese firms – PetroChina, which acquired the SOCO operation, and Sinopec – together produced 4.75m barrels of low-sulphur crude in the year to November 2013. Output is rising fast: production from the two blocks in the east jumped from 2.2m barrels in 2010 to 3.9m in 2012, and is set to almost double in the medium term. “We plan to raise production to 7.1m barrels by 2017,” Ts. Amraa, vice-chairman of PAM, told OBG. Such expansion could lend new credence to government’s plans to develop Mongolia’s first domestic oil refinery (see analysis).
PAM estimates possible total reserves at 4bn-6bn barrels. This figure includes 2.4bn barrels of proven oil at three operating blocks registered in December 2012, making the country the world’s 34th largest by proven reserves. Mongolia also holds promise in oil shale, which, unlike shale oil, requires significant heating to transform into oil. In April 2013, PAM signed an exclusive joint-survey contract with US-based Genie Energy on 34,470 sq km in central Mongolia. While prospecting is still in early stages, PAM hopes Genie will apply for a PSC in the next two years to explore more extensively.
The largest producer, PetroChina, produced 3.6m barrels in 2012 on Blocks 19 and 21, and has drilled 600 vertical wells of which half were producing in 2013. The oil, once extracted, is then trucked 150 km to China. In the nine years to 2019, the firm plans to produce 662m barrels. Some 14 other independents are also prospecting, including China’s Mongolia Energy Corp, Gold BC, Donshen Oil, Wolf Petroleum, Manas Petroleum and Petro Matad. Local mining companies hold exploration licences, but these remain largely inactive. In recent years, other Chinese contractors have joined the market’s largest driller, PetroChina-subsidiary DQ, including Great Wall, Bo-Chai and Chun-Li.
While most exploration currently centres on the producing eastern region, independent oil companies such as PetroMatad, Wolf and MEC have increased investment in the western and central regions, which hold significant potential given their proximity to active fields in Inner Mongolia.
“Mongolia is under-explored, and the west-central areas are the region’s last frontier acreage,” Ridvan Karpuz, Petro Matad’s director of exploration, told OBG. Having shot 2D seismic studies in 2013, PetroMatad is seeking international partners for a farm-out to drill two wildcat wells in west-central plots in mid-2014. Wolf Petroleum, meanwhile, is planning to raise new equity to finance its 2D seismic workplan in 2014. “Farm-outs by private PSC-holders are not specifically covered by the law, nor prohibited,” PAM’s Amraa told OBG. “As long as the rights to the PSC don’t change hands, we see no need for government approval.”
A new petroleum law due to pass in the first half of 2014 aims to clarify PSC terms and attract more investment upstream. At present PSCs are granted for five years, renewable up to 14, with negotiable royalties and cost-recovery of 40% that can be rolled over annually. Negotiated royalties have gradually increased: Block-19, signed in 1993, was exempt; Blocks 21 and 97 yield 7.5%; all other PSCs pay 13.5%. Such negotiations can run long, however. “The priority of the National Security Council (NSC) is to attract as many countries to invest as possible,” Amraa told OBG. “Yet the involvement of PAM, the Cabinet and the NSC in approving PSCs means the process usually takes one and a half to five years.”
The new law, though still being debated in parliament as of the end of 2013, would lengthen the initial PSC timeframe beyond five years but cap it at 12, and set the range for negotiated royalties at 5-15%. The aim is to spur more investments from oil independents. “Given the large size of our exploration blocks, the lower maximum timeframe of PSCs will force oil independents to raise more funds in order to execute more extensive work programmes faster,” Amraa told OBG.
Additional survey work also needs to be carried out in the country. “There is no regional survey database in Mongolia yet,” Karpuz told OBG. “We would like to work with PAM to shoot one.”
Though Mongolia faces looming power shortages and adverse terms of trade for fuel imports in the short term, the new administration is seeking to fast-track longstanding plans to expand power generation capacity, invest in much-needed grid upgrades and develop mid-stream oil processing. Attracting private and foreign investment to these initiatives will be key. Above all, Mongolia needs a coherent and predictable investment framework. This would help leverage its abundant natural resources, both fossil-based and renewable, into the energy it needs to reach its goals.
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