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


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


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


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.

Issues for wind power


Debate regarding wind power has centred on a number of issues. The body of evidence is accumulating, revealing problems and solutions are being proposed, but some of these issues still require much further study and analysis.

It should be emphasised that it is not within the scope of this report to present a full summary of all the evidence, arguments and conclusions in these matters. The purpose is to raise the issues and to point out that questions exist. Some of these questions have been answered, others remain to be answered.

Grid balancing

In order to maintain security of supply, a second-by-second balance between generation and demand must be achieved. An excess of generation causes the system frequency to rise whilst an excess of demand causes it to fall. To sustain the balance, the electric system must provide power at the instant the load demands it, and at the prescribed frequency and voltage limits. Variations outside these limits can either cause protective systems to shut down large parts of the network or can cause extensive damage to delivery equipment and customers’ facilities. This is a vital issue for intermittent sources of energy.

Network balancing problems have occurred because of the variability of wind power and these have sometimes been serious. It has been pointed out that this is the normal state of an electrical system and a wholly fossil fuel powered system requires a spinning reserve in any case. However, evidence suggests that wind power can exacerbate this problem.

Grid extension

Because in many countries wind turbines are sited in remote areas where wind speeds are high but the distance from load centres is considerable, the transmission of large amounts of energy has placed burdens on the transmission system and caused congestion. This has been acute in Germany where the main fossil fuel base load generators are located in industrial areas, requiring little transmission capacity and the transmission network has developed accordingly. It will also need to be addressed in the UK where offshore wind farm developments in the northwest of Scotland will place burdens on the transmission network to transport power south. Because wind proposals have not always come to fruition, National Grid at one time proposed requiring a deposit from wind developers to link them to the grid.

The effects of sudden and intermittent flows of electricity reach beyond the location of the wind generators, unless they are in an electrical island. Examples of this are found in Poland and the Slovak Republic. The Polish TSO, Polskie Sieci Elektroenergetyczne SA has stated that it will need to make new investment in transmission capacity to accommodate the additional power from Germany. Likewise the Slovak TSO, SEPS, Slovenska elektrizacna prenosova sustava, has told ABS that they will need to construct major new interconnection capacity with the Czech Republic to accommodate the surges of wind power flowing south from Germany.

Historical experiences with wind energy – USA experience


Several states in the US have encouraged extensive development of wind energy.

Investigations in California following the power crisis reported to the state legislature that because electricity systems must be kept in balance on a real time basis in order to maintain system reliability and because output from wind power is intermittent, variable and unpredictable, other dispatchable generating units must be kept immediately available to provide back up. These must be kept connected to the grid and running below peak capacity or in spinning reserve mode. These units incur costs which are part of the real cost of wind power generation.

A study during the 2006 California heat storm revealed that output from wind power significantly decreased as peak demand increased, due to greater air conditioning and other demands that stem from high temperatures.

A sudden drop in wind speeds in Texas in December 2009 almost resulted in blackouts in western parts of the State.

The US Department of Energy (DoE) has published a comprehensive report listing the steps to implement in order to develop wind energy. The programme aims at installing a total of 100 MW in each of sixteen states by 2010, recently raised to 30 states. Three primary targets are identified:

  • Technology characterisation and data collection
  • Tools and methods of development
  • Applications and implementation

A substantial research and development programme is needed to examine both high and low wind speed turbines, including the deployment of smaller wind systems in distributed settings. The thrust of this structured plan is that the DoE wishes to assess the future potential for wind and to move progressively towards a manageable system; in small regional units rather than large wind carpets like the European systems.