Historical Wind Energy Developments in India

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2009 Developments

In September 2009 a broad feed-in tariff calculation formula was introduced by the Central Electricity Regulatory Commission (CERC), which varies by technology, resource intensity and return on equity. The tariff incorporates small projects and projects that can‘t benefit from the government’s accelerated depreciation programme. Developers can apply for this incentive up to the end of March 2012.

In December 2009, the Ministry of Power also approved a Generation Based Incentive (GBI) subsidy of INR 0.5 per unit of electricity fed into the grid with a cap of USD 33,000 per MW per year for a minimum of four years and a maximum of 10 years.

Eligible projects include those commissioned after 17 December 2009. The scheme is limited to the first 4,000 MW of eligible capacity that is grid connected by March 2012. As of January 2011, only 394 MW of wind capacity was registered with the GBI from independent power producers, with thermal power projects keen to use wind power to meet their mandates for carbon emission reductions. Thus, a review of the GBI is anticipated.

A total of INR 3.8 billion (USD 84.4 million) was earmarked for the scheme in December 2009.

Wind power projects selling to third parties or merchant power plants are excluded under the scheme.

2010 developments

In January 2010, India’s Central Electricity Regulatory Commission announced rules for trading with renewable energy certificates (RECs). These certificates can be bought by companies to meet their renewable energy requirements according to state renewable portfolio standards. There are plans for a national agency to administer the certificates trading. Eligible projects have a minimum capacity of 250 kW and are commissioned after March 2010. They are not allowed to receive feed-in tariffs. Non-solar RECs must trade within the price band of INR 1.5 to 3.9 per kWh (USD 0.033 to 0.087 per kWh). Thus, there is more of an incentive for developers to opt for the feed-in tariff in Haryana state if the projects are eligible, as the feed-in tariff is above INR 3.9 per kWh.

The government introduced an INR 50 tax on every tonne of coal produced or imported into India, with money raised being used for a new Clean Energy Fund.

Also in 2010, the MNRE announced an intention to leverage INR 25 billion (USD 500 million) from the Clean Energy Fund to establish a Green Bank, working with IREDA.

Historical Data Series: Indian Water resources

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India has 20 river basins, both major and minor. The largest of these, in terms of area, is that of India’s largest and longest river, the Ganges (known in India as the Ganga) and its major tributary the Yamuna. The Ganges flows southeast along the foothills of the Himalaya mountain range until it enters Bangladesh and then turns southward to empty into the Bay of Bengal.

Other major Indian rivers include the Narmada (India’s largest westward-flowing river), which flows through central India into the Arabian Sea, and three eastward-flowing rivers, the Godavari, the Krishna, and the Cauvery, which flow through southern India into the Bay of Bengal. Besides these, there are two other major rivers which pass through India: The Indus, which rises in Tibet and flows northwest through the Northern state of Jammu and Kashmir before entering Pakistan, and the Brahmaputra, which also rises in Tibet and flows southwest through the eastern Indian states of Arunachal Pradesh and Assam before entering Bangladesh and joining the Ganges.

There are many players in India’s hydroelectric sub-sector. Twenty-two different ownership entities are involved in the hydroelectric facilities that are of at least 100 MW in capacity. The most important hydroelectric generator, though currently not the largest in terms of generating capacity, is the National Hydroelectric Power Corp. (NHPC), which was created in 1975 with the mandate to develop India’s hydropower potential. NHPC presently owns and operates nine hydropower facilities, ranging from the 1,000 MW Indira Sagar Project to the 5 MW Kalpong Power Plant in the Andaman & Nicobar Islands. Its total generating capacity is 5,295 MW from 14 hydro plants, with 3,145 MW coming online since 1996 due to the commissioning of the 1,000 MW Indira Sagar and 520 MW Omkareshwar plants. In August 2009 the NHPC successfully launched an initial public offering and became a listed company one month later.

The Bhakra Beas Management Board (BBMB) is currently one of India’s largest hydropower generators. It was created in 1966 to manage the supply of water, in Himachal Pradesh state, from the Sutlej and Ravi-Beas rivers whose waters flow into Punjab, Haryana, Rajasthan, and Delhi. BBMB presently operates five hydroelectric facilities, with a total generating capacity of 2,866 MW, including the two power plants at Bhakra Dam whose combined capacity is 1,325 MW.

Developing Water Markets

For years, water has been a heavily subsidised commodity. In the United States, for instance, farmers in desert regions of California have received water at unrealistically low prices for decades. A small number of these farmers, in fact, have controlled as much as 80% of the state’s water supply. This pattern of subsidised water use has been repeated in countries worldwide, for different groups within the population. A new economic scheme for water is becoming prevalent in many countries, as for the first time, governments and people are realising that water itself is a commodity with a real market value.

Water has been traditionally viewed as an inexhaustible resource that should be available to everyone at little or no charge. However, this view is changing with demand outstripping supply wherever it is treated as a “free” good. A recent study by Johns Hopkins University predicts that, under current water management, 35% of the world’s population will run short of water in the next 25 years. With the impending water shortages countries are looking for new and innovative ways to manage this valuable resource. Most experts agree that the opportunities for expanding traditional water sources such as groundwater and reservoir storage is limited due to rising environmental and economic costs. For example, in some parts of the world, the cost of tapping new groundwater supplies has tripled as a result of aquifers being drawn down. The draw down is also causing pollution problems, further driving up the cost of treating water. With limited supplies of fresh water, some users are turning to desalinisation to meet the rising demands. Even with recent technological advances, desalinisation still comes with a hefty price tag.

With the high cost of development limiting expansion of water supply, the growing demand for water will be kept in check by higher prices and supplies to meet the demand will have to come from reallocating water from current uses. Neither of these has occurred because prices and allocation have been determined in the political arena. In that setting, powerful interest groups have prevented any meaningful increases in water prices or reallocations.

A look back to 2010 Government Support for Wind Energy in the UK

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The government wants their extensive plans paid for by private investment (currently estimated at GBP 100 billion +), incentivised by an extension of the Renewables Obligation subsidy mechanism until 2037. Under the Utilities Act 2000 the government has the power to issue a Renewable Obligation Order requiring electricity suppliers to supply a certain proportion of their energy from renewable sources. To prove they have got their energy from renewable sources they have to buy Renewable Obligation Certificates (ROCs), which are issued to generators of renewable energy, alongside any renewable energy they source. The ROCs represent approximately GBP 35 per MWh (actual price March 2009: GBP 35.76), so a wind farm operator can sells its MWh for around BP 65 with the accompanying ROC compared with a coal fired power station selling its MWh at around GBP 30 – a significant incentive. Industry watchdog Ofgem determines the value of ROCs on an annual basis.

In 2009 onshore wind accounted for 33% of the total number of ROCs issues and offshore wind only 8%. To boost the offshore industry, the government allowed multiple ROCs per MWh for offshore projects reaching financial close in the 2009/10 and 2010/11 financial years.

In Scotland, a similar system runs, called the Renewables (Scotland) Obligation

The 2010 Finance Bill upholds the value of offshore electricity at one ROCs (Renewable Obligation Certificates) per megawatt-hour for accredited onshore wind farms and two ROCs for offshore wind farms until 2014. For the 2010/2011 financial year the buyout price for ROCs was GBP 36.00. The government also awarded GBP 50 million of financial aid to offshore wind turbine manufacturing and equipment testing plants.

It is estimated that suppliers in the Scotland, England and Wales will need 0.124 ROCs per MWh to meet their renewable obligations and 0.055 ROCs per MWh in Northern Ireland.

Starting in April 2010 feed-in tariffs were available for households and local authorities that want to produce their own renewable energy electricity. The tariffs range from 34.5 pence per kWh for capacities below 1.5 kW to 4.5 pence per kWh for capacities between 1.5 and 5 MW for twenty years and will keep pace with installation. It is estimated that 2% of the UK’s electricity demand will be met by small scale renewables by 2020 and will be eligible for these feed-in tariffs.

Government support for Wind Energy in Ireland – A historical look back to 2010

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In April 2006 the price support mechanism for renewable electricity was changed. The previous competitive tendering system was replaced with a feed-in tariff with prices of EUR 54 to EUR 57per MWh (EUR 0.054 to EUR 0.057 per kWh) for wind projects depending on size.

In August 2009 a new feed-in tariff was announced for offshore wind power at EUR 140 per MWh (EUR 0.14 per kWh). Also in 2009, the government offered a feed-in tariff for small scale renewable energy of EUR 0.19 per kWh, but only 4,000 projects registered up to 2012 will qualify.

The feed-in tariff schemes are capped at 1,450 MW. Currently projects with a total capacity of 3,000 MW are being processed for grid connection offers. If accepted, it is uncertain if they will be eligible for feed-in tariff.

The Department of Communications Marine and Natural Resources (DCMNR) is responsible for wind energy policy in Ireland. There are two programmes under which wind energy R&D may be funded; the Parsons Energy R&D Awards, and the Sustainable Energy Ireland Renewable Energy R&D Programme, but no specific R&D budget or programme dedicated solely to wind energy research exists.

Sustainable Energy Ireland (SEI) operates the only government-funded wind energy R&D programme. SEI has provided 50% funding to Tapbury Management for a study into a new electricity storage system.

The Foreshore Administration of the Department of Communications, Marine and Natural Resources (DCMNR) deals with the licensing of Offshore Electricity Generating Stations. The Foreshore Acts, 1933 to 2003 require that a Foreshore Lease or Licence must be obtained from the Minister for Communications, Marine and Natural Resources for undertaking any works or placing structures or material on, or for the occupation of or removal of material from, State-owned foreshore. Developers require a Foreshore Licence in order to conduct site investigations for assessing the suitability of a site for constructing and operating a ‘wind powered electricity generating station’ and a Lease in order to erect and operate an offshore wind farm.

A big challenge for the industry is that standard planning permission granted to a wind farm development expires after five years and it can take up to six years to process a grid connection application. Planning permission often expires before approval is granted for grid connection. An extension of planning permission can be granted to projects where substantial work has been undertaken. However, the definition of what constitutes substantial work is unclear.

Historical Look at the Indonesian Coal Sector

wh_01200766The latest player on the international coal stage, alongside China, is Indonesia. The country has enjoyed one of the most rapid recent increases in coal production in the world, rising from 400,000 tonnes (t) in 1981 to 253 million tonnes (Mt) of coal in 2009. It is now the second largest exporter of hard coal in the world. Despite economic difficulties, coal production has not only been maintained but even extended and increasingly channelled into exports. The country produces around 30 to 40 Mt of lignite.

The policy pursued by post-Suharto governments of assigning autonomous rights to the provinces involves, among others, a shift in power away from the mining ministry towards provincial governments. The authorities there were hardly prepared for this or were unable to continue the necessary administrative work properly. Also, the mining law generally valid until now is practically suspended. Instead, the authorities are using their new powers to raise taxes and levies or are attempting to exert political influence over the mining companies. On top of this, comes a revitalisation of the unions, which are putting growing pressure on companies through strikes and plant occupations and also the financial demands of local townships. The consequence has been a serious worsening of the investment climate.

Indonesia was the second largest exporter of hard coal in 2009 with 230 Mt, after Australia with 259 Mt. Coal mining was hardly affected by the East Asian economic crisis during the years 1997/98. Coal production was extended and channelled into exports despite runaway inflation in the national currency and a wave of cancellations and delays in numerous coal-based IPP power plant projects and firmly agreed long-term coal supply contracts. A more momentous impact on the coal mining sector, however, has come from centrifugal political forces and the turmoil they have brought since the presidential change in 2000.

Coal industry restructuring in Russia

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The coal industry has undergone a major restructuring since 1993, in two phases. The first saw large-scale closure of uneconomic mines, resulting in an increase in the sector’s competitiveness and labour productivity. The second, from which the sector is still struggling to emerge, concentrates on improving the productive fields and opening new ones. The success of this process is critical for the sector to meet the rapidly growing domestic demand that current planning foresees. The coal industry also strives to compete in international coal markets and competes internationally to raise capital. It is hampered by social burdens and a lack of finance, worsened by the generally unstable investment climate in Russia.

The main provisions of Russia’s Energy Strategy to 2020 are based on the increasing coal use in the heat and power sector to lower the dependence on gas in the fuel mix. The provisions project the share of coal in the fuel balance to increase from about 20% in 2000 to 21-23% in 2020, with a matching decrease in the shares of natural gas and oil to meet the increasing electricity and heat demand and increase energy efficiency.

To achieve this, coal production will need to rise by almost 75% by 2020, to 340-430 Mt a year. Despite the sector’s progress towards restructuring during the 1990s, several factors raise concerns about its ability to meet this challenge. Doubts are attached to the sector’s capacity to attract the needed investment, the competitiveness of coal as an input fuel versus natural gas and the environmental implications of the increased mining and use of coal.

Under the Soviet system, the Ministry of the Coal Industry of the USSR controlled regional production associations. It was succeeded in 1991 by the Ministry of Fuel and Energy (Ministry of Energy since 2000) and RosUgol, the state-owned coal company. The restructuring process created 14 regional coal production companies and 11 regional coal associations to act as regional holding companies, in addition to a few stand-alone private mines.