Despite abundant resources, Mongolia has struggled to shore up its energy security and decrease its dependence on Russia for refined fuel and electricity. The government has made some headway in diversifying fuel imports and improving its terms of trade, while several mid-stream projects could develop domestic refined fuel production. Meanwhile, important refurbishments of Mongolia’s ageing power infrastructure in 2014 will ensure adequate electricity supplies for the next three years, but new greenfield plants are needed in the long term. New wind farms will provide some respite, but larger coal-fired and hydroelectric plants at various planning stages will be key to balancing fluctuating supply and demand. As Mongolia develops a mix of larger renewables projects and decentralised off-grid systems, it is also seeking to develop its coal value chain to produce both power and coal-based fuels.
The growth in demand for power and heat in the country is outpacing supply: in the five years to year-end 2013 demand for electricity rose 30% to 5.5m KWh and for heat by 19.5% to 5.2m Gcal, while installed generating capacity only expanded by 6.8% to 5.13m KWh, according to figures from the Ministry of Energy (MoE). Growth in demand for power fell 5.3% year-on-year in 2013 in line with the economy, but authorities expect it to rise five-fold by 2030, particularly driven by a mining sector that already accounts for 40% of demand. Mining projects will double demand by 2020: aside from the Oyu Tolgoi (OT) mine’s requirement of up to 450 MW of power starting in 2017, processing plants at Tavan Tolgoi (TT) and Sainshand could add another 300 MW each.
Coal remains the dominant energy source, although its share of Mongolia’s power consumption, eroded by growing reliance on Russian electricity imports, fell from 91.4% to 79.3% between 2010 and 2013, while imports rose from 7.6% to 18.8%, according to the MoE. Renewables like solar and wind account for 0.8%, alongside hydro’s 0.9% and diesel’s 0.1%. While the 220-KV transmission line connecting the central grid to Russia could handle up to 255 MW, the latest annual contract is set at 210 MW, although Mongolia is keen to avoid expanding this if at all possible, as denomination in roubles exposes it to currency risks. “Although the existing 220-KV line to Russia could handle more, our current contract allows for only 210 MW of imports,” said B. Ganbat, head of dispatching at the National Dispatching Centre (NDC) . “Talks are under way to potentially expand this.” China also provides low-voltage connections for border soums, or districts, and 200 MW to OT under a four-year contract until 2017.
With five weakly connected grids, Mongolia’s power infrastructure is fragmented. The Central Electricity System (CES), covering 13 provinces along the Trans-Mongolian railway from Ulaanbaatar to Darkhan, accounts for 80.2% of the country’s 901-MW capacity, with 814 MW. The neighbouring Eastern Electricity System (EES) and Altai-Uliastai Electricity System are connected to the CES, but are smaller at 36 MW and 15 MW, respectively. The 12-MW Western grid remains standalone with a small connection to Russia, while the 24-MW Southern Electricity System (SES) centred on Dalanzadgad is being connected to the Choir-Mandalgovi line, built by local conglomerate MCS Holdings with a transmission capacity of 20 MW.
Although installed capacity at the seven Russian-designed, coal-fired plants was 856 MW in 2013, actual output was 615 MW given ageing infrastructure. The country has several combined heat and power plants (CHP), including: CHP 2, operated at 43% of its 21. 5-MW installed capacity in 2013; CHP 3, which runs at 80% of its 136-MW potential; and CHP 4, which recently had its capacity expanded by 100 MW to 580 MW.
The 48-MW power plant in Darkhan operates at full capacity, while Erdenet’s facility operates at 80% of its 36-MW capacity. The five plants also produce 265 MW of industrial steam and 194.3 MW of heating for soums, although the latter remains highly inefficient during the country’s long winter due to heating infrastructure. Providing 70% and 17.6% of the capital’s electricity and 65% and 32% of its heating, respectively, CHP 4 and CHP 3 form the backbone of the CES. Their refurbishment in 2014 added a total of 170 MW of power and 263 kcal of heat to their combined output, ensuring adequate supply to the CES until 2016.
While the Energy Law of 2001 unbundled the sector, segregating five power generators, a transmission grid operator and 10 distributors, all but the Darkhan distribution company, which was privatised in 2005, remain state-owned utilities. Under the single-buyer model, the National Electricity Transmission Grid Company buys at a regulated tariff. A 2011 amendment to the energy law calls for cost-recovery tariffs in three tiers by 2015. CHP 4 sells power at MNT40 ($0.03) per KWh; CHP 2, CHP 3 and Darkhan sell at MNT60 ($0.04) per KWh; and Erdenet sells at MNT90 ($0.05) per KWh. “With electricity prices highly regulated by the government, the inefficient state-owned utilities operate at a loss,” O. Gonchigdorj, Grand Power’s executive director, told OBG.
The technical operator, NDC, has operated a spot market and auctions since 2007. New sources of wind power, from the 50-MW Salkhit wind farm since 2013, have proven more expensive at $0.095 per KWh. Prices for Chinese and Russian imports, which fluctuate widely every year with currency movements, averaged MNT180 ($0.11) per KWh and MNT110 ($0.07) per KWh, respectively, in 2013, according to MoE figures. While the government subsidises power generators directly, with MNT60bn ($36m) allocated in the 2013 budget, it also does so indirectly by fixing coal prices at state-owned producers like Baganuur, Shivee Ovoo and Ulan Ovoo at artificially low prices of around MNT18,000 ($10.80) per tonne.
Although end-user power prices were raised twice, in 2011 and 2013, they remain below cost recovery. Prices were raised 30% and 18.32%, respectively, for miners and businesses in July 2013, while an attempted MNT5 ($0.003) per KWh tariff increase for residential users in August 2014 was reversed under social pressure. “Given social frictions, it is unlikely we will reach cost-recovery pricing in the coming years,” Ganbat told OBG. If the government carries through on its early 2014 plans for privatisations of key assets such as Baganuur and Shivee Ovoo, however, and as more expensive independent power plants emerge, end-user tariffs will need to increase greatly. “If we do not liberalise the power sector, it is very difficult to see which thermal coal producers will be profitable,” N. Enkhbayar, director of the Economics, Finance and Investment Policy Division at the Ministry of Mining’s (MoM) Strategic Policy and Planning Department, told OBG. “Liberalisation in the power sector seems like a prerequisite to privatising state-owned coal producers.”
While tariffs remain low amid social pressure, the government is forging ahead with efforts to expand the electrification rate beyond its current 70%. For nomadic herders in Mongolia’s sparsely populated countryside, roughly a quarter of the 3m population, subsidised portable solar photovoltaic systems have proven successful. The 100,000 Solar Ger Electrification Programme, launched in 1999, was successful once the role of soum administrations in sales and services was strengthened in 2006. A total of 50 service centres were established and now serve all 21 aimags, or provincial governments, and have leveraged the opportunity to sell electrical appliances. By 2014 some 104,000 solar home systems were installed, backed by two $3.5m World Bank grants and $6m from the Netherlands that subsidised half of the $300-500 set-up costs.
Connecting the burgeoning urban population will be key to attaining the nationwide electrification target by 2020. Depending on the severity of the winter, the population of Ulaanbaatar can increase by between 50,000 and 200,000 each year. The growing ger, traditional felt yurts, districts in Ulaanbaatar’s outskirts are heated through the open burning of coal, with some 160,000 gers burning an estimated 200,000 tonnes of raw coal and 160,000 cu metres of fuel wood annually, according to the MoE. This makes the capital one of the world’s most polluted during the winter, with harmful dust levels seven times higher than the laxest World Health Organisation standards. Public programmes are subsidising clean coal stoves, with the aim of replacing 90% by 2015, and electricity bills for low-income clients are discounted at 50%. Distributors like the Ulaanbaatar Electricity Distribution Company connect several thousand new clients a year, with a budget of MNT11bn ($6.6m) for upgrades to existing the low-voltage network, smart metres and new connections, but rural-urban migration is outpacing power supply.
Building on the solar photovoltaic scheme’s success, the 2007 Renewable Energy Law sets a target for expanding renewables’ share of the energy mix to 20-25% by 2020 through off-grid systems and larger projects steered by the National Renewable Energy Centre. Over-dependence on coal makes Mongolia the world’s 10th-most energy-intensive and fifth-most carbon-intense economy, according to the World Energy Council. Under the renewables plan’s first phase to 2010, alternative energy’s share of electricity output was expanded to the 3-5% range with the development of two hydro dams in Durgun (12 MW) and Taishir (11 MW) and 12 renewable energy systems (solar and wind) for soum centres. The second phase consists of larger projects like the 50-MW Salkhit wind farm, with four more wind farms under development.
Fluctuations in wind currents mean that more consistent renewable sources like hydro are in great demand. Mongolia boasts considerable resources, equivalent to 1.1m MW of potential capacity, according to the US National Renewable Energy Laboratory. Centred on the Gobi desert, Dornod and Sukhbaatar, sparsely populated Mongolia holds 400,000 sq km of land suitable for wind and solar farms, with an estimated 946 TWh per year of wind potential, 1300 KWh per sq metre over an average of 320 sunny days, 900 MW of geothermal, and some 3800 rivers and streams capable of supporting over 6400 MW of a hydropower stream.
The government also plans to award build-operate-transfer concessions for large hydro dams, to expand its current 24 MW of hydropower, in addition to completing smaller western dams at Durgun and Taishir. By early 2015 feasibility studies had been completed or were under way for five dams: Delger (250 MW), Egiin (220 MW), Orkhon (100 MW), Erdeneburen (60 MW) and Chargait (24.6 MW). With three-year development periods though, no significant new hydropower will come on-line before 2018. In the long term there is potential for exports to North Asia through initiatives such as SoftBank’s Asian Super Grid or Gobitec, which is modelled on the Desertec Foundation in North Africa, although such projects will require state backing.
The mismatch between peak load and demand, which drops by 40% at night, has prompted energy efficiency and grid balancing measures, including discounting tariffs by 50% during the evening to promote electrical heating for households and nighttime operations for industries. New transmission lines have been built from Mandalgovi to TT (110 KV) and from TT to OT (220 KV), while the MoE expects to complete a feasibility study for the 220-KV Ulaanbaatar-Mandalgovi line in 2015. Yet as renewables’ share grows, significant back-up capacity will be needed from coal. The CHP 5 and TT power plants will near financial close in 2016 and will be key to the central grid.
Despite abundant reserves of lignite coal, delays in concluding power purchase agreements (PPAs) have stalled a series of mine-mouth power plants. For the four-turbine, 600-MW power plant near the 124mtonne Chandgana-Tal coal mine, roughly 200 km from OT, developers of the $800m project are still awaiting finalisation of a PPA they submitted in September 2012. With the TT plant likely to meet OT’s needs, Chandgana’s proposed output could be transmitted to the CES along the 220-KV line currently under construction. The New Asia Group’s 35-MW Zavkhan plant is planned to be completed by year-end 2015, having struck a 250, 000-tonnes-per-annum (tpa) supply agreement with Aspire Mining’s northern 255m-tonne Ovoot coal deposit in July 2014. Other plants have stalled entirely, such as the 3600-MW, export-oriented mine-mouth plant at Shivee Ovoo, planned under a 2009 memorandum of understanding signed with China’s State Grid Corporation.
The surge in Mongolia’s hydrocarbons consumption over the past decade –12% annually for diesel and 5% for gasoline – to an aggregate 1.3m tonnes in 2013 was met almost entirely by expensive imports from Russia’s state-owned Rosneft, according to the Petroleum Authority of Mongolia (PAM). With the prospect of domestic fuel supply four years away, the priority in the near term is to diversify fuel suppliers (see analysis). According to PAM, consumption rose from 814,000 tonnes in 2010 to 1.3m in 2013, and is expected to triple to 2m-3m tonnes of diesel and 600,000-1m tonnes of gasoline by 2020. Rosneft has long provided the lion’s share of imports, as much as 99.1% in 2010, but its share fell to 76.5% in 2013, with imports growing from Belarus (9.3%), South Korea (7.2%) and China (5.1%), according to PAM.
Imports from China increased following a March 2013 swap agreement with PetroChina, which produces most of Mongolia’s crude, which saw 10,000 tonnes of crude output per month exchanged for discounted Euro III-compliant gasoline. Eager to defend the traditional dominance of fuel from its East Asian refineries, Rosneft subsequently cut prices sharply to secure a new five-year supply agreement. While a 2011 law limiting fuel station operators to 30% of market share frustrated Rosneft’s bid to establish 100 stations locally, in May 2014 it secured a five-year deal with several Mongolian fuel-retailers for over 1m tpa at discounted prices of $900 per tonne, down from $1400 in 2013. However, with the contract’s pricing formula based on Singapore Platts’ gasoline and diesel prices, it is independent from Russian domestic market fluctuations. Additionally, the contract did not require the Mongolian firms to buy only from Rosneft.
Cheaper imports should ease some fiscal pressure on a government that has actively intervened to offset the impact of high oil prices and the local currency’s devaluation. Through the Price Stabilisation Programme (PSP) the Bank of Mongolia lent MNT192bn ($115.2m) in year-long loans subsidies at a rate of 3.8%, compared to a market average of 17-19%, to fuel importers in 2013, but gradually shifted to six-month, foreign exchange forwards. While there are 17 licensed fuel importers, only 11 have accessed PSP support. However, the surge in state support was unable to offset the impact of the currency’s 40% depreciation against the dollar since mid-2012, squeezing importers’ ability to invest in infrastructure. A planned $4m upgrade to the Zamyn Uud-Erenhot fuel trans-shipment depot on the China-Mongolia border from 6000 cu metres to 16,000 cu metres has been delayed beyond its original 2014 completion date; however, Mongolia still maintains minimum reserves above 83,000 tonnes, enough for 30 days of import cover.
While imports will remain central to Mongolia’s fuel mix in coming four years, the government hopes comprehensive legislative reform in 2014 will spur significant new exploration in this fledgling crude oil producer (see analysis). Mongolia remains vastly underexplored, with only 47% of exploration blocks surveyed between 1994 and 2013, with 31,129 sq km of 2D and 5915 sq km of 3D seismic imagery. Its 2.4bn barrels of proven reserves put Mongolia on par with larger producers like Gabon and Colombia, yet smaller average basin sizes, the heaviness of its crude and remote locations contribute to higher costs. Despite Soviet exploration since the 1950s, output only started in 1998.
Chinese state-owned firms operate Mongolia’s three producing blocks. PetroChina, which acquired US-based Soco’s concession in 2005, holds production-sharing contracts (PSCs) for Blocks 19, 21 and 22 in the northeast, while Sinopec operates the much-smaller Block 97 to the south. Output, driven by Block 19’s Tamsag field, has grown exponentially from 6000 barrels per day (bpd) in 2010 to 14,000 bpd by 2013 and 21,000 bpd by September 2014, according to PAM. Private investors have poured billions into Mongolia’s upstream over the past two decades, drilling a total of 1210 wells for exploration and 567 for production, but most PSCs remain under-drilled.
Chinese firms such as PetroChina subsidiary DQE and Sinopec’s Shengli Oilfield dominate oilfield services, although Mongolian mine drillers like Erdene Drilling and Western firms like Major Drilling Group are also bidding for oil work. Domestic players are also expanding their share of non-drilling business. “While Mongolian companies have been gaining market share in seismic and environmental services, drilling remains dominated by Chinese firms,” T. Amarzul, executive director of Petro Matad, told OBG.
Joining the Club
All 30 blocks, covering 560,000 sq km, are now spoken for, with 23 under PSCs to 16 companies and seven PSC applications under review as of late 2014. “The existing blocks have been offered for exploration through international open tenders and companies are now either in the process of exploration or in the process of signing PSCs,” Ts. Amraa, vice-chairman of PAM, told OBG. Based on preliminary results, western blocks in Mongolia have been compared to producing fields in China. Interest has come from existing investors, such as Chinese majors, and Western firms like Anadarko and BG Oil. “The main Chinese producers have aggressively been looking for new blocks, either as new PSCs or as farm outs, since early 2014,” said Amarzul. “We see this as mainly a government-to-government phenomenon.”
The largest concession holders by acreage are juniors like London-listed Petro Matad and Australia-listed Wolf Petroleum with three blocks each. Holding 74,400 sq km and a drill-ready block, Wolf Petroleum has struggled to attract partners for its project given the absence of rules on farm out agreements prior to the July 2014 Petroleum Law. While it is a frontier region, the country’s west presents strong potential, but requires significant investment. Estimating a potential of between 462m and 2.2bn recoverable oil reserves at its SB block, Wolf opened its data room to potential farm out partners in 2013 and announced a $1.3m rights issue in October 2014 to fund further exploration.
Petro Matad has also found a farm out partner to drill wildcat wells at its blocks. While Chinese firms have shown interest in the company’s Block 22, Petro Matad entered into an $28m deal for a 78% interest in Blocks 4 and 5 with the UK’s BG Group, with the evaluation process expected to be completed in 2016.
The most encouraging drilling results in 2014 came from China’s Zongshen, which had 14 exploration wells in Block 11 all hit oil, and the firm will move to 3D seismic surveying in 2015. With Mongolia’s entire output trucked to China, PetroChina has applied to build a midsized pipeline to handle its surging production. The government has proven ambivalent, however, given its ambition to develop a national refinery.
Indeed, PSCs contain domestic sale obligations, should refining capacity be built. Funded by the Japan Bank for International Cooperation, a feasibility study was completed in November 2013 for a 2m-tpa refinery in northern Darkhan for $1.5bn, far from current output in the country’s east. In early 2014, however, the National Security Council struck down the plan for its reliance on imports from Russia. More realistic options centre on a smaller refinery in Dornod, roughly one-fifth the size. Meanwhile, Mongolian-listed HBO il is studying refining domestic crude in North Korea, having acquired a 20% stake in Rason City’s Sungri refinery, although the deal also covered offshore upstream exploration.
New legislation seeks to unlock Mongolia’s potential in unconventional hydrocarbons, ranging from oil shale to coal bed methane (CBM). “There are opportunities to explore unconventional oil on the existing or future blocks, in addition to the blocks that will be relinquished from existing contractors,” Amraa told OBG. In 2013 the US Energy Information Administration estimated Mongolia held roughly 4trn cu feet of recoverable shale gas and 3.4bn barrels of shale oil, although actual reserves may be much higher. The National University of Mongolia reported 787.5bn tonnes of oil shale rock in place in 2012, although the recoverable oil conversion rate ranged from 10% to 100%, depending on the quality of the rock. These are split among 13 oil-baring basins, and, in contrast to US shale oil where oil is trapped in low-porosity rock, oil shale is a high-kerogen rock that must be heated, oxygen-free, to 325°C to release hydrocarbons.
“Although Mongolia’s oil shale has a yield of only around 6%, compared to China’s 8% and some Eastern European countries’ 16%, our oil shale is of higher quality,” N. Tselmuun, vice-president of local conglomerate Mongolyn Alt Corporation (MAK), told OBG.
Long Road Ahead
While substantial, these deposits will require significant appraisal to determine their commercial and environmental viability. New exploration terms for unconventional fuels under the 2014 Petroleum Law have attracted significant interest, with 17 oil shale and CBM proposals under PAM’s consideration in September 2014. NYSE-listed Genie Oil and Gas signed a five-year, joint-survey agreement with PAM in April 2013, which was expanded to a 60, 000-sq-km exploration-licence in September 2014. “Available geological evidence suggests that our licence area may contain world-class deposits of thick and rich oil shale well-suited for our in-situ extraction technology,” said Yuval Bartov, Genie’s chief geologist, at a conference in Ulaanbaatar in September 2014.
Covering all aspects aside from transport, a pre-feasibility study by BDO on a 50,000-bpd oil shale operation valued the full project at $4bn. “According to our economic feasibility study, the breakeven price for oil shale production in Mongolia would be in the $60-$70 range,” Michael Jonas, Genie’s executive vice-president, told OBG. Once commercial quantities are certified, Genie expects to secure a PSC by 2017 to begin 2500-bpd production for an initial $300m. Surveying costs of around $5m prior to the 2014 licence would not be reimbursed under the PSC, although Genie will be given preferential treatment in negotiating the contract. MAK holds a smaller 14.5-sq-km licence adjacent to its Khuut thermal coal mine, with an estimated 487m tonnes oil shale and 190m tonnes coal reserves, and will select partners in 2015.
Both the petroleum and mining laws of July 2014 aim to monetise gas associated with major coal deposits. The MoM estimates that Mongolia holds 5trn10trn cu metres of potential CBM reserves, centred on four main deposits at MAK’s Nariin Sukhait mine, stateowned Baganuur, Erdenes Tavan Tolgoi and Mongolia Mineral Corporation’s Khotgor mine. Enabling legislation should catalyse significant investment in Mongolia’s upstream. Foreign investment and expertise will also be key in the power sector, where groups like GDF Suez and Posco Energy have already shown their appetite.
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