The power and heating, hydrocarbons, renewable and nuclear segments of Mongolia’s energy structure are all undergoing important changes. These are occurring as the country tries to move away from its old dependency on one major fuel source – coal – and on its two giant neighbours – Russia and China.

The energy market is beginning to open up, with huge potential for investors. Oil-exploration outfits, solar panel manufacturers, power plant experts and dam builders could all play a key role in the development of the sector. The government is keen to encourage foreign investment as well, as it is aware of the need for the sector to provide for what could be exponential domestic economic expansion in the years ahead, in tandem with surging growth in neighbouring China.

ENERGY IN A COLD CLIMATE: Mongolia’s energy sector comprises a small hydrocarbons sector that is developing quickly, although still largely at the exploration phase, along with an electricity and heating sector that is facing challenges in terms of capacity and structure.

Mongolia’s hydrocarbons sector is under-explored, making estimates on total reserves difficult, with the three producing blocks also still being explored. Output from these is almost entirely exported, as Mongolia lacks domestic refining capacity. As a result, the country imports its petroleum products. Some 890,000 tonnes were imported in 2010, with annual growth of around 10%, according to the Petroleum Authority (PA).

Meanwhile, in electricity and heating, the main energy source has been coal, of which Mongolia has significant reserves estimated at 150bn tonnes, with proven reserves of around 20bn tonnes. New mining projects at the Tavan Tolgoi open pit mine and elsewhere are likely to see more of this come on-line in the future.

In late November 2011 the Mongolian government granted a licence for a new 600-MW thermal power plant (TPP), the largest of its kind by size in the country. Canada’s Prophecy Coal will use coal from its Chandgana Tal deposit — some 60 km from Underkhann city — to power the Chandgana mine-mouth plant. The plant will be operated by Prophecy’s Mongolian subsidiary, East Energy Development.

Coal is also used by many families who are not connected to the grid as a staple source of fuel, particularly in winter months, when it is burnt in its raw form, creating pollution concerns, particularly in Ulaanbaatar.

Other energy sources used to provide power are solar and wind (see analysis), hydro and diesel generators, as well as imports. The current balance is about 80% from TPPs, 12% from imports, 2.5% from hydro, 0.5% from wind and solar, and the rest from diesel.

ELECTRICAL FRAMEWORK: Much of the machinery and equipment in Mongolia’s electricity sector dates back to Soviet times. The sector has recently acquired some of the organisational and business characteristics of a liberal model, but has also retained some of the characteristics of a planned economy in that the state continues to play an important roles as a stakeholder and as a regulator, customer and price adjuster.

The electrical power system is divided into three regions, the Central Energy System (CES), the Western Energy System (WES), and the Eastern Energy System (EES). A fourth, southern system is also in the works.

The CES is by far the largest of these systems, in terms of generating capacity and demand, for it services the capital, Ulaanbaatar, plus several other major urban and industrial centres, such as Darkhan, Baganuur and Erdenet. Even within this region, however, there are still large areas of land that are difficult to reach and sparsely inhabited. These last two characteristics are even more prevalent in the WES and EES regions.

The CES accounts for around 95% of the 814-MW, total-installed capacity in the country and has five combined heat and power (CHP) plants to its name. These provide both electricity and heat for district heating systems – equally vital in a country where winter temperatures can drop as low as -40°C – along with steam for industrial purposes. The CES also has a 220-KV double-circuit line connection to neighbouring Russia, from where it imports very limited amounts of power.

All of the CES’s power plants are coal fired, with three located in and around Ulaanbaatar, another at Darkhan and the fifth at Erdenet. The three at the capital – TPPs Two, Three and Four – vary in age. TPP Two was constructed and expanded between 1961 and 1969, while TPP Four dates to the 1983-1991 period. TPP Four also has the largest installed capacity, at 540 MW, with the other two having 21.5 MW and 136 MW, respectively. The Darkhan TPP, built in 1965, has an installed capacity of 48 MW and the Erdenet TPP, built between 1987 and 1989, has a capacity of 28.8 MW.

ONLINE CAPACITY: Available capacity is somewhat lower. According to a 2010 US Agency for International Development (USAID) report, TPP Two had an available capacity of 17.6 MW, TPP Three had 105.1 MW and TPP Four had 432 MW. Darkhan TPP had 38.6 MW of available capacity and Erdenet TPP 21 MW.

In terms of heat production capacity, TPP Two delivers 31 gigacalories per hour (Gcal/hour); TPP Three, 518 Gcal/hour; and TPP Four, 1045 Gcal/hour. Darkhan TPP, meanwhile, supplies 181 Gcal/hour and Erdenet 120 Gcal/hour. District heating is provided between September 15 and May 15. Steam is provided year-round.

The EES has one coal-fired CHP centred on Choibalsan with a capacity of 36 MW and available capacity of 29.5 MW. The WES, meanwhile, operates entirely on imported electricity from Russia. In addition to these capacities, there are also many isolated local networks supplied by generators or renewable energy sources.

COSTS: The coal supplied to the CES’s TPPs is governed by a series of government-fixed tariffs, all of which are below cost price. Extraction costs for the coal are currently around MNT21,000-22,000 ($16.38-17.16) per tonne, while the set tariff for sale to the TPPs is MNT18,000 ($14.04) per tonne. Transport is also provided below cost – the state-owned Ulaanbaatar Railway (UBTZ) charges around 60% of the actual cost of transport, with UBTZ shipping around 5.5m tonnes of coal per year for domestic use. This means a loss for the railway but a benefit to the TPPs, which account for around 85% of domestic coal consumption.

OWNERSHIP: The three systems operate within a legislative framework that was first laid down in the 2001 Energy Law. This served to establish the Energy Regulatory Authority (ERA) and 18 joint-stock companies covering generation, transmission and distribution under the single-buyer model — along with the National Dispatching Centre (NDC) — with the intention of moving the sector towards privatisation. Ownership of the 18 joint-stock companies was initially divided between the Ministry of Roads, Transportation, Construction and Urban Development (MRTCUD) at 41%, the State Property Committee (SPC) at 39% and the Ministry of Finance (20%). The NDC, meanwhile, was shared by the SPC and the MRTCUD on a 49:51 basis.

The hoped-for private sector involvement has largely not materialised, however, and the sector remains almost entirely state-owned, albeit by several different state bodies. In the CES, the five generation companies that are based around the TPPs sell their heat and power to the Central Regional Electricity Transmission Company, which then sells to 10 different distributors, who then finally sell on to the end-users.

TRANSMISSION: The systems include their own transmission networks, each of which pose its own challenges. Given the wide dispersal of communities and the large distances involved, often only small amounts of power have to be sent many kilometres. “The only solution is to install power lines carried on single poles,” said J. Khand-Ish, the head of the technical Policy Department with the Central Regional Electricity Transmission Grid (CRETG). “In really strong winds, snow and other bad weather, however, these can be damaged, leading to outages.” A break in the line can take time to find and repair as well, leaving distant communities without power for significant periods. There is also a high loss ratio of power within the transmission system to rural areas, due to the great distances the power needs to travel to serve these far-flung locations.

Thanks to a number of foreign aid programmes, many of the substations are relatively new, even if the infrastructure connecting them is old. German and Swedish aid agencies in particular have helped here, as have soft loans from the government. A wave of new power line building is also under way, financed by state funds, with these lines set to be transferred to the regional systems on completion. The aim is to at least double electricity lines where there are now only single cables.

Loss rates in transmission and distribution have also been declining, thanks to this new investment. Between April 2010 and 2011, central region’s transmission and distribution companies reduced losses by 19.4%, in line with a long-term loss-reduction programme. The initiative aims to bring losses in the CES down from 17.3% in 2010 to 16.9% in 2011 and 16% by 2013.

PUBLIC MANAGING: There is currently a prohibition on privatisation of the transmission network under the 2001 Energy Law, with no plans to change this. Given the large investments required and the social, non-market nature of much of the transmission network, the state seems likely to continue to be the manager and owner of this system for some time.

The CES has 1044.1 km of 220-KV transmission lines, with 661.3 km of this double line. It has a further 2981.8 km of 110-KV line, with 501.7 km of this double, and 12.8 km of 35-KV lines, 6.8 km of which is double. The system also has 6182.2 km of 6-15-KV lines. The CES has 59 substations, six of which handle 220-KV lines and the rest 110-KV lines. The 220-KV lines also handle Russian imports. Some 255 MW has been made available by Mongolia’s neighbour, with around 130 MW of this going to the CES and 10 MW to the WES.

The WES’s transmission system consists of 463 km of 110-KV lines, 266 km of 35-KV lines, and 546.5 km of 6-15-KV lines. The EES has 188 km of 110-KV lines, 116 km of 35-KV lines and 319 km of 6-15-KV lines.

These systems currently connect around 70% of the country’s population to regular electricity supplies, meaning that some 30% of the population has no regular electricity connection. This is increasingly significant in terms of blank spots on the transmission system in the country’s south, where the major new mining interests at Tavan Tolgoi and Oyu Tolgoi are located.

DISTRIBUTION: With the exception of the Darkhan-Selenge Electric Distribution Network (DSEDN), which is 100% owned by the private Khasvuu Group, all the electricity distributors remain state-owned. All except DSEDN are also operating at a loss. DSEDN was privatised in 2003 when the government also privatised two heating distribution companies, Baganuur heat-only boiler and Nalaikh heat-only boiler.

Tariffs are set by the ERA, with regulated prices for generation set first, then for transmission and distribution, and finally for the end user. Since 2006 there has also been a spot market, and an auction market since 2007, which enables generating companies in CES to bid for any incremental electricity demand. The NDC acts as the spot market operator and runs the auctions. A bilateral contract market has also been proposed though it has not yet been implemented.

The tariff is set on a cost-plus basis according to the climate and other specifics of each region, with 12 heat and eight electricity tariffs currently operating. This allows for some tariffs to be set according to the income of the customer. There is also some cross-subsidy between heat and electricity.

In 2010 parliament approved a plan for the ERA to gradually raise tariffs through to 2014. This move may potentially make the sector more financially viable. Two price hikes, averaging 9.5% each, were implemented in 2011. A 15% rise is due in 2012 and another 4.5% in 2013. Increases in heating and hot water tariffs are also planned. From 2011 to 2014, the average electricity tariff will thus rise from MNT87.4 ($0.07)/KWh to MNT115 ($0.09)/KWh, heat tariffs from MNT349.6 ($0.27)/cu metre to MNT712.2 ($0.56)/cu metre, and hot water tariffs from MNT1591.4 ($1.24) per-person-per-month to MNT3241.8 ($2.53) per-person-per-month.

UNDER PRESSURE: Demand for electricity and heating has been increasing at a steady rate, and with the likely expansion of the economy, will rise further still. At the moment, there are two main centres that require an increase in capacity as a result of surging demand: the expansion of Ulaanbaatar and other urban centres; and the mining industry, which could spark expansion of the industrial sector in the coming years.

According to figures from the Asian Development Bank (ADB), electricity consumption in 2010 stood at 3.38bn KWh, up from 3.03bn KWh in 2009 and 2.53bn KWh in 2004. Electricity production was 4.31bn KWh in 2010, 4.04bn KWh in 2009 and 3.42bn KWh in 2005. Around 62% of demand goes to industry and construction, 24% to communal housing, 4% to transport and communications, 1% to agriculture and 9% to others.

According to the Mongolian Energy Sector Master Plan (MESMP), drawn up in 2002, energy demand was forecast to grow at an average of 2.9% per year between 2002 and 2020. Clearly, though, the above consumption figures show that the rate has been rising much faster than this – ADB figures suggest 11%, while the government puts the increase at around 7%. There are also reports of many unfulfilled connection requests in Ulaanbaatar and elsewhere, and 60% of the city’s population live in unconnected ger (tent) districts, which are largely off the grids, suggesting that potential demand increases could be far higher. By 2020, ERA estimates that Ulaanbaatar will need an additional 1.27 GW of installed electricity capacity and 970 Gcal/hour of installed heat capacity. “The city needs heat and electricity,” said Armine Guledjian, a consultant to Firebird Management, which specialises in former Soviet Union markets. “Summer demand is half that of winter, with bottlenecks in supply often emerging.”

Much of future industrial demand will likely be in the south, where the Tavan Tolgoi and Oyu Tolgoi mines are located. The expansion of the network to cover this area is thus a major priority. Another is to establish an integrated system, capable of balancing supply across the country, while also tackling the outdated and polluting TPP-dependent generation system.

PIPES: The government unveiled its Programme for an Integrated Power Energy System of Mongolia (PIPES) to run from 2007 to 2040. The first phase, from 2007 to 2012, aims to establish permanent power supply to every settlement, along with the modernisation of existing TPPs and the building of a fifth TPP for Ulaanbaatar. PIPES also envisages a hydroelectric plant on the Egiin River with a 220-MW capacity, and another such plant on the Delger, both connected to the CES.

Progress on these points is already evident, with private sector involvement key. TPP Five, which will have a 450-MW electricity and 587-MW thermal capacity, is to be built on the site of TPP Three in south-central Ulaanbaatar, under a build-operate-transfer model. Bidders for the plant were to be shortlisted in late 2011, with the winner signing contracts in March 2012. Construction is expected to be completed by 2015. The ADB is the mandated advisor in the tendering process, which is for a public-private partnership (PPP). The first phase is expected to involve an investment of $670m.

There is also a great deal of enthusiasm regarding hydropower. “Coal-fired power stations are very inflexible,” said N. Erdenesukh, a senior specialist with CRETG’s international cooperation administration division. “With hydro, you can ramp up or down output more easily, allowing us to balance the system more effectively.”

A $4.2m engineering services contract for the Egiin River dam was awarded in 2007 to Poyry of Finland by the Energy Research and Development Centre (ERDC), with a target for completion of 2013 for a 90-metre, roller-compacted-concrete 210-MW dam. The ERDC, which operates under the Ministry of Mineral Resources and Energy, is the agency responsible for the implementation of government energy plans, such as PIPES.

Improvements in the legal framework, notably the new concessions law, which provides for a variety of PPP contracts, have assisted in the development and implementation of such systems. The government is committed to using this approach in its efforts to develop the power and heating system as well.

SOUTHERN FRONT: The first phase of PIPES also includes plans to cover the southern mining districts of the Gobi Desert. A new, southern energy system is being established with the assistance of the German state aid agency, GTZ. The operators of the Oyu Tolgoi mine, meanwhile, had planned to construct a 220-KV line across the border to nearby China, with the aim of importing power. This raised concerns from the government, however. Instead, it gave the go-ahead for the construction of a 750-MW plant in the area of Tavan Tolgoi and Oyu Tolgoi. As the mines will likely still need power before the completion of such a project, the transmission line to China is expected to go ahead as a stop-gap measure. Other mines in the central and southern regions have begun constructing their own lines to connect to the CES grid, yet any line of 220-KV or above must be state-owned.

Phase two of PIPES (2012-22) will see the construction of interconnection lines between what will then be four regional energy systems. Two more hydro plants are also envisaged and will be located on the Hovd and Orhon Rivers. Geothermal is also set to be investigated during this phase, along with a boost to solar. By the third phase, the whole country should be linked up through a high-voltage integrated power grid. The PIPES scheme dovetails with the 2007 Renewable Energy Law, and the 2005-20 National Renewable Energy Programme, which aim to see renewable energy take up 20-25% of total energy production by 2020.

OUTLOOK: Demand for both power and heating is likely to continue rising beyond the levels foreseen in the MESMP. The long-term industrial development plans being implemented should accommodate the exponential growth in demand for power the country is expected to see in the years ahead, particularly if ambitions to develop local value-added industries utilising the country’s vast mineral wealth take off. The process of urbanisation also looks set to continue, with Ulaanbaatar’s current schemes to transform the ger districts into fully developed neighbourhoods, adding thousands of new customers to the grid. It is expected there will be much private sector interest in these infrastructure developments over the next decade. The sector is still largely on the ground floor, but its lofty ambitions indeed make for a healthy investment atmosphere.