Indonesian Coal producers


Coal mining has evolved on ‘greenfield’ sites and under the control of what used to be the Ministry of Mining and Energy or its Directorate General for Mining. By 1999, state-owned coal reserves had been offered in three tranches for inter-national development under a bidding procedure, the first tranche in 1981 with 11 ‘Coal Contracts of Work’ (CCOWs), the second in 1993 with 17, and the third in 1997 with 114. A fourth wave of contracts came after 1999 from the by-now autonomous provinces.

The ‘contractors’ undertake to prospect for and explore the coal deposits located in their concession area, possibly to engage in mining development and, in return, are granted exclusive rights for a term of 30 years subject to a royalty (free mine) of 13.5% of proceeds. The contractors are also obligated to offer Indonesian investors at least 51% of the mining stock after a ten year operating period. In 2001, this provision affected two foreign investors, Rio Tinto/BP and BHP Billiton.

While one of the deals went smoothly, the other was accompanied by conflicts as regards company value and the nomination of buyers. Besides foreign and local investors, the state-owned P.T. Tambang Batubara Bukit Asam has started production on Sumatra, mostly for domestic consumption. This company is to be privatised in a second attempt.

Most of the companies are based on generation-I CCOWs, representing over 80 Mt, generation-II CCOWs with about 40 Mt and generation-III CCOWs with a mere 10 M t.

Coal mining without official approval, too, has evolved in the meantime, with output at four Mt per annum. These are small local companies that operate with the tacit consent of officials.

Indonesia‘s coal policy, for the time being at least, prevents the international consolidation movement from spreading to Indonesia. To that extent, Indonesia‘s hard coal mining sector is an important element for healthy competition on the world market.

Historical experiences with wind energy – Western Denmark 2005


In 2005, Eltra, transmission system operator for the western grid in Denmark (now merged in Energinet) reported that in 2003 a total of 11 primary power units supplied 3,516 MW of power, 558 district heating plants supplied 1,593 MW and 4,161 wind turbines supplied 2,379 MW. Western Denmark has wind conditions similar but not as good as those in Britain and in 2003 wind turbines achieved a capacity factor of 20-24%, compared with Britain’s 24.1% and Germany’s 15%. UCTE claims an average capacity factor of 20% for its European TSO members.

In 2003 in Denmark, although wind turbines accounted for 20% of total power production, most of it had to be exported to ensure stability in the domestic grid, since much of it was surplus to requirements at the time of production. In 2003, 84% was surplus and only 4% contributed to domestic Western Danish power consumption. In the next year, 2004, the total amounted to 85% of production but only 6% of electricity consumption. According to Eltra this surplus had to be disposed of at a price less than the company paid. Recent assessments have suggested that these exports cost Danish consumers up to EUR150 million a year. At that time the Danish government enforced obligatory purchase schemes for wind generated power on the network operators and although this has now been abandoned, subsidies continue.

Norway and Sweden have been able to absorb the surplus of power by reducing their output of hydro power, or using the power to pump water to elevated reservoirs for later conversion into electricity. On the one hand, this affects the reduction in carbon emissions from wind power since the electricity produced in these hydro plants does not produce emissions either and the main supply in Denmark was delivered by CHP fossil fuel fired plants during these periods. On the other hand, the export to Norway and Sweden enabled wind energy to be stored in hydro facilities when the electricity was produced in periods of low demand.

Electric Vehicles

electric-car-charging-stationThere is a potential domestic and export market for electric vehicles for Korean manufacturers and is expected to hold 10% of the global market in 2015. The Korean government is planning to install 27,000 or more additional power charge stations for the 2.4 million electric vehicles that should be on the road by then.

In twenty years’ time it is expected that the domestic industry will be worth USD 54.5 billion annually and will create 50,000 new jobs. Domestic demand should create a market worth USD 6.59 billion (KRW 74 trillion) and the export market to be worth USD 4.37 billion (KRW 49 trillion). Additional benefits to the development of a smart grid are expected to be a 230 million ton reduction in carbon emissions, savings of USD 4.19 billion (KRW 47 trillion) from a reduction in energy imports and savings of USD 0.29 billion (KRW 3.2 trillion) from the evasion of building new power plants. The Korean government is planning a call for USD 21.6 billion worth of investment from the private sector.

The Korean Electric Power Company (KEPCO) is collaborating with Hyundai-Kia Motor to develop electric vehicle charging stations and a standard charging interface. The company is also developing two battery chargers for electric vehicles: one a quick charger that achieves 80% battery life in 20 minutes and one an overnight charger. If these batteries pass field tests, NRGEXPERTexpects these chargers to be the standard for the country due to KEPCO’s monopoly of the electricity market.

In 2010 the car manufacturing division of Hyundai produced its first all-electric vehicle, BlueOn. The car is powered by lithium polymer batteries and can run for 87 miles at a top speed of 81 miles on a single charge, which take 6 hours. It should be on the market in 2012.

In June 2010 the company signed a memorandum of understanding with Raser Technologies, based in Utah, to develop 5 MW of solar power and three extended range electric trucks (E-RBEV) for the US market. This is the second US collaboration for the company, in 2004 Chevron and Hyundai-Kia collaborated on a five-year demonstration project to develop fuel cell cars and fuelling stations.

LG has a solar cell and battery business. In 2012 the company’s subsidiary, LG Chem, is expected to commission an electric car battery factory in Holland, Michigan, which has contracts to supply rechargeable batteries for GM’s Chevy Volt and Ford Focus electric vehicles. Most of the investment costs for the USD300 million project are covered by an American Recovery and Reinvestment grant (USD 151 million) from the US government and tax credits from the Michigan state (USD 130 million). Another Korean company, Nexcon Technology, is planning to open a factory nearby to supply components for LG Chem batteries.

Another Korean company, Samsung, has developed a line of batteries for permanent grid storage and electric vehicles through its SDI and end user technologies to potential display energy usage, e.g. smart phone and televisions. Through its collaboration with GE, Samsung is planning to infiltrate the market for ‘smart’ low voltage appliances such as air conditioners, lighting and TVs.

Potential legislation currently being discussed includes plans to exempt electric cars from consumption, acquisition and registration taxes, which is worth an estimated USD 3,000 (KRW 3.5 million) per vehicle. Along with the lifting of a ban on cars that solely use electricity as a power source.

Investing in the US Solar Industry in the late 2000s

At the peak of the first solar boom, as many as 18 big banks and financial institutions in the US were willing to help finance installation of wind turbines and solar arrays, taking advantage of generous federal tax incentives, but that number dropped to four. In the first half of 2009 debt financing for large scale solar power parks has nearly halted and while there are some signs of recovery, overall investment was originally expected to remain low for the remainder of 2009 and will possibly remain low into 2010. Small companies with weak cash flow will be badly affected for another year and solar PV company consolidations are expected to continue throughout 2010

However, Wells Fargo Clean Technology Investment Banking Group, a merger between the Wells Fargo Securities and Wachovia Securities, launched two new solar investment programmes in 2009 and 2010:

SunPower programme: launched in June with a budget of $100 million for commercial-scale solar projects. Under the program, SunPower enters into power purchase agreements (PPAs) with qualified customers and Wells Fargo finances the solar power systems. The first projects installed under the scheme were a 1.1 MW system for the University of California, Merced, and a 1 MW system for the Western Riverside County Regional Wastewater Authority, both commisioned in December 2009;

Solar Home Equity: launched in January 2010 to help Colorado customers install solar systems on their homes. Qualified customers who use a home equity loan or line of credit to finance a solar energy system for their home will receive $1,000 in incentives.

This is in addition to the company’s existing BP Solar Programmes, SunEdison Solar Programmes and FRV Solar Programmes.

Last year $ 1.4 billion was invested in solar by venture capitalists, more than in any other clean energy in the US.

Sasol Gas to Liquid

Since 2007 Sasol has been operating a gas-to-liquid (GTL) plant, ORYX GTL, in Qatar and is expected to use shale gas reserves to produce a liquid diesel fuel at a similar plant in South Africa. The plant in Qatar is part owned by Qatar Petroleum, which has a 51% stake in the project, with Sasol owning the other 49%. Payback time for the plant is estimated to be in the region of five years. Currently the plant is operating near capacity of from 275 mcf (8 mcm) per day of natural gas the plant can produce 32,400 barrels per day of gas-to-liquid diesel, naphtha and liquefied petroleum gas (LPG). At its peak the plant produced 36,860 barrels per day. The ultra-low sulphur diesel produced from the plant has a premium price in the market.

A second GTL plant, Escravos GTL, is under construction in Nigeria with completion expected in 2012. Once the plant has been ramped up to capacity, it should be producing 32,400 barrels per day. Sasol, National Nigerian Petroleum Company and Chevron Nigeria Limited have a stake in the project, with Chevron as the manager and Sasol holding a 10% stake.

A third plant in Uzbekistan is in the feasibility stage. Uzbekneftegaz, Sasol and Petronas signed a joint venture agreement for the project in December 2009. A site in Qharsi in the south close to the border of Turkmenistan has been identified. Methane rich gas from the Shurtan gas field should be converted to up to 36,000 barrels per day of diesel, kerosene, naphtha and LPG.

Other gas-to-liquid plants have been proposed along with an expansion to the Oryx plant in Qatar. In September 2010 Sasol announced plans for a GTL plant in Calcasieu Parish, Louisiana. Over the next eighteen months the company plans to evaluate the viability of a 2 million tonnes per annum and a 4 million tonnes per annum facility. This follows by announcement by Sasol in December 2010 for an Ethylene Tetramerisation unit in the same location.

The capacity of GTL plants has been increasing and thus may be able to benefit from economy of scale, along with the potential use of next generation catalysts.

Balancing supply and demand with energy storage and renewable energy

A large number of interconnected, intermittent generation sources operating over a large spatial scale may effectively smooth out the variability between individual generation sources. But, still variation will occur in output in the short and longer term.

Coupling intermittent renewable sources to a number of electricity production and storage sources could be used to meet the energy demand of a given facility or community, known as a hybrid power system. The power sources used depends upon the local geographical and temporal constraints, and can be used to meet demand from remote applications such as communication stations, military installations and rural villages. Full renewable power hybrid systems are in operation and have been mainly applied to remote hybrid systems in China. One of the most cost effective hybrid systems for a microgrid, a small-scale grid, is a photovoltaic array and a micro hydro turbine.

Therefore, more or less electricity is generated than meets demand. Excess electricity can be exported; dumped; stored as another form of energy and/or other electricity sources feeding into the grid can be modified accordingly. An electricity deficit can be met by electricity imports, ramping up or turning on of other electricity generating sources (backup power); and use of stored energy. Another option is to use demand management to balance supply and demand imbalances.

Storage is one of the more expensive options to balance supply and demand, but is increasingly more attractive in order to meet high renewable energy penetration targets. Another way countries are balancing their energy generation and consumption is by expanding the reach of their networks through imports and exports.

The potential for exporting and importing electricity depends upon the grid infrastructure, interconnections with other grids and the ability for the importers to absorb surplus electricity generated and exporters to meet any shortfalls in the importers electricity demand. For example, excess electricity generated from wind turbines in Denmark is exported to Norway, Sweden and Germany through grid interconnections.

In Norway and Sweden, the imported electricity is absorbed by reducing output from the countries’ hydro power plants or by using the electricity to pump water to higher elevations in a pumped storage plant. Electricity is also exported from Denmark to Germany. Although, with the expansion of wind power in Germany, it is unlikely that electricity will continue to be imported and exported in roughly equal quantities between the two countries.

Cost-benefit of carbon capture and storage (CCS)

As there are only a handful of small scale projects in operation, it is difficult to assess the cost-benefits of carbon capture and storage. Projections indicate that there is a clear cost-benefit for CCS and funding for projects could come through a levy on coal fuelled power plants. The Pew Centre on Global Climate Change in 2008 estimated that the construction of thirty 400 MW coal CCS plants at US $ 30.1 billion would save US $ 80 to US $ 100 billion by 2030 in abatement costs. In the same year, the European ‘Impact Assessment of the Geological Storage of CO2’ report estimates that building ten 400 MW coal CCS power plants would cost € 9 billion and would save € 60 billion in carbon abatement costs in the next twenty years.

McKinsey estimates that the lifetime costs for the first twelve commercial-scale coal CCS plants will be in the region of € 5 to € 13 billion. Considerably less than the estimated costs of for the EU to meet is renewable energy targets. For the UK, likely to be a major market for CCS technology, costs for CCS for coal are estimated to range from € 60 to € 90 per tonne of CO2 abated for the first commissioned plants, i.e. before 2015. Then, after 2020, costs for CCS are expected to fall to € 35 to € 50 per tonne of CO2 abated. Favorable compared to the abatement costs for renewables that are estimated to currently range from € 95 to € 205 per tonne of CO2 in the UK.

Support and prospects for carbon capture and storage (CCS)

Support for CCS is available worldwide, but with most focus on the EU, USA, Canada, China, Japan and Australia. Each region is focusing on a similar range of technologies and it is still too early days to determine which technology will come out on top.

The UN estimates through its BLUE roadmap scenario that US $130 billion will be needed over the next ten years in order to commission 100 demonstration projects, and a total of US $ 6 trillion between now and 2050 to get over 3,000 CCS projects off the ground.