The United Kingdom Shale Gas Market (Historical Report Series)

The UK is a net importer of natural gas and has been a net importer since the 1970s. The only exception was a period in the mid 1990s to mid 2000s when production overtook consumption and new natural gas discoveries were reported. Since then natural gas production has been falling dramatically along with natural gas reserves. The R/P ratio for gas reserves in the UK is reported as 4.9 years.

In 2009 natural gas accounted for 47% of consumption as natural gas been increasingly part of the energy mix. The replacement of coal-fired plants with natural gas has resulted in 38% of primary energy consumption from natural gas.

LNG counts for a quarter of imported gas, and Norweigan imports for over half of all imports.

These imports could potentially be replaced by domestic unconventional gas production including shale gas. The Department of Energy and Climate Change has identified the best onshore shale resources as the Upper Bowland Shale of the Pennine Basin, the Kimmeridge Clay of the Weald Basin and the Lias of the Weald Basin. Many of these sites are located near well-protected beauty spots which makes gaining approval for shale gas projects extremely challenging.

Development of shale gas has been slow. Only three onshore oil and gas licences were awarded to shale gas projects in the 13th Round of Onshore Oil and gas licensing in 2008. The furthest along is the Preese Hall site owned by Cuadrilla Resources, where one exploration well has been drilled.

iGas Energy is the main developer of unconventional gas resources and has identified potential shale and coal bed methane resources in the UK. In 2005 its subsidiary, IGL, entered into a joint venture agreement with Nexen in Canada, which has experience developing coal bed methane. Based on the country’s current projects, NRG Expert expects that coal bed methane will be the company’s main focus for the foreseeable future.

Canadian Oil

Using the traditional method of calculation of conventional oil reserves, the world total is 1,333 billion barrels, of which 56.6% are situated in the Middle East, 14.9% in Latin America, 10.3% in Europe and Central Asia, 5.5% in North America, 9.6% in Africa and 3.2% in Asia Pacific. If oil sands are included, on a country by country basis, Saudi has the most reserves measured at 265 billion barrels at the end of 2009, then Canada at 176 billion barrels and Venezuela at 172 billion barrels. Canadian oil reserves are estimated as 143 billion barrels, which is more than the total oil reserves of fourth placed Iran (138 billion barrels) and fifth placed Iraq (115 billion barrels).

The National Energy Board (NEB) distinguishes between two types of non-conventional oil obtained from deposits of Canadian oil sands.

Bitumen (also known as crude bitumen) – ‘a highly viscous mixture, mainly of hydrocarbons heavier than pentanes. In its natural state, it is not usually recoverable at a commercial rate through a well’.

Upgraded Crude Oil (also known as synthetic crude) – ‘a mixture of hydrocarbons similar to light crude oil derived by upgrading oil sands bitumen’.

Canada’s ‘discovered recoverable resources’ of oil sands bitumen are quoted by the NEB as 49 billion m3 (over 300 billion barrels). Of the remainder (shown as ‘proved amount in place’ in the table above), 9,650 million m3 (9 billion tonnes) consists of synthetic crude recoverable through mining projects and 38,850 million m3 (36.3 billion tonnes) consists of crude bitumen recoverable through in-situ extraction.

Within these huge resources, the ‘remaining established reserves’ at end-2009 (shown as ‘proved recoverable reserves’ above) have been assessed by the Canadian Association of Petroleum Producers (CAPP) as 8,871 million barrels of mining-integrated synthetic crude oil and 4,706 million barrels of in-situ bitumen.

Bitumen deposits are located in Lower Cretaceous sandstones and in carbonates overlaid by Lower Cretaceous sandstones. The major deposits are in three geographic and geologic regions of Alberta; Athabasca, Cold Lake and Peace River, covering a 140,200 km2 area (14 million hectares). Of which only 0.3% is producing bitumen. Reserves are expected to extend over the border into the neighbouring Saskatchewan province. One oil company, Oil Sands Quest, estimates there could be the region of 50 to 60 billion barrels of bitumen located there.

Very little extra-heavy oil is located in the reserves and is of little economic value.

The scale of the water supply problem

The global population is growing by 1.1% or 77 million people a year, almost all in the developing countries.

The percentage of people served with some form of improved water supply rose from 79% (4.1 billion) in 1990 to 82% (4.9 billion) in 2000 and 87% (5.8 billion) in 2008.

Over the same period the proportion of the world’s population with access to sanitation facilities increased from 55% (2.9 billion people served) to 60% (3.6 billion) in 2000 and to 61% (4.1 billion) in 2008. At the end of 2008 13% (0.9 billion people) of the world’s population was without access to improved water supply and 49% (2.6 billion people) lacked access to improved sanitation. The majority of these people live in Asia and Africa. Although the greatest increase in population will be in urban areas, the worst levels of coverage at present are in rural areas.

The number of people without water or sanitation will increase during the next twenty years.

Over 25 countries suffer chronic water shortages and this number will increase.

In the OECD countries, just less than 100% of the population has access to safe water and modern sanitation. In the low income countries 63% have access to water; much of it unsafe and 35% have some form of sanitation, mostly without even primary waste treatment.

Globally, 50% of drinking water is lost through leaks in pipes and illegal drawing.

90% of wastewater in developing countries is allowed to flow untreated into rivers, lakes and seas.

UNESCO claims that unsafe drinking water and poor or non-existent sewage account for 80% of diseases in the developing world.

Mature infrastructures of water and sewage systems exist in developed countries but in many cases they are 100 to 200 years old and well past their safe design life.

Investment forecasts for global water and sanitation provision disagree wildly but they agree in one aspect; they are all enormous and mostly lie between USD 1 to 2 trillion over the next decade. About one half of this will be required for replacement of mature assets in the industrial countries and one half will be needed to achieve minimum levels of provision in the developing world.

Overview of Hydropower

Although a small source of primary energy, at only a fifth of the biomass contribution, hydropower is the largest renewable source of electricity. It has been in use for many years and is now considered a conventional form of power generation.

Although there are hydroelectric projects under construction in about 80 countries, most of the remaining hydro potential in the world may be found in developing countries, particularly in South and Central Asia, Latin America and Africa. Individual countries outside of these regions with remaining hydropower are Canada, Turkey and Russia

Hydropower represents 15.9% of the world’s electricity generating capacity. The theoretical potential worldwide is 2,800 GW, about three times the 978 GW which had been exploited by the end of 2009. However, the actual amount of electricity which will ever be generated by hydropower will be much lower than the theoretical potential because of environmental concerns and economic constraints.

44% of the world’s hydropower was generated in just four countries in 2009 – in the United States, Canada, Brazil and China. Asia accounted for 29%, an improving share on account of China’s expansion of hydro, followed by North America with 21% and Latin America with 21% and other regions accounting for 29%.

In Western Europe and the United States the scope for additional hydro capacity is limited. Eastern Europe is expected to maintain its reliance on fossil fuels and nuclear.

Hydro-electric power plants can generally be divided into three technology types.

‘High head’ power plants are the most common and generally employ a dam to store water at an increased elevation. Water can be stored during rainy periods and released during dry periods, providing a consistent and reliable production of electricity. Some of these plants have enormous heads as high as 1,000 meters. Most large hydro-electric facilities are of the high head variety.

‘Low head’ hydro-electric plants are power plants which generally use heads of only a few meters or less. Power plants of this type may use a low dam or weir to channel water, or no dam and simply use the ‘run-of-the-river’.

‘Pumped Storage’ facilities use excess electrical system capacity, generally available at night, to pump water from one reservoir to another reservoir at a higher elevation. During periods of peak electrical demand, water from the higher reservoir is released to generate electricity. Pumped storage sites are not net producers of electricity, it actually takes more electricity to pump the water up than is recovered when it is released but they are able to store electricity for use at a later time when peak demands are occurring. Storage is even more valuable if intermittent sources of electricity such as solar or wind is hooked into a system, which is then termed ‘hybrid’.

The British experience of privatisation.

A good test of the private versus public argument is, however, to be found in the United Kingdom. Most privatisation in the global water and sanitation sector is limited to operational management but in Britain, the assets of the water boards were sold to private investors. Until 1989, most British water was delivered by public utilities, organised around river basins rather than municipalities. As in America, there were some small private companies, but these were little more than historical curiosities. Yet in 1989 the privatisation programme introduced by the then prime minister, Margaret Thatcher, reached water, and all ten English and Welsh water utilities were floated on the stock market. Instead of retaining the assets in public hands and franchising out operations and maintenance, as France had done, the British government chose to privatise the assets as well.

How does the record look 17 years on? In terms of quality, service delivery and efficiency, the answer is excellent; in terms of stock market performance, less so. At the time of privatisation, thanks to years of Treasury cheese-paring, the British water utilities faced a daunting backlog of capital investment needed to comply with European water-quality directives. This persuaded the government to hand the new water companies a lavish sweetener. They were forgiven all their debt and allowed to raise prices. The first director of Ofwat, the new water regulator, now concedes that the initial regime was too generous. Ofwat’s price regime was tightened at reviews in 1994 and 1999. By then most of the much-needed capital investment had been made, and efficiency gains had kicked in. Yet several utilities, especially those that had taken on the biggest debts, were under pressure. A painful windfall tax was duly imposed in 1997 and shareholders began to grumble. Mergers between utilities were frowned on by the regulator, so that avenue to cost-cutting was closed, and the utilities had to look for other solutions. Some merged with regional electricity companies, others were sold to the French or other foreign companies. Welsh and Yorkshire (now Kelda) Water pondered becoming mutually owned companies. The regulator blocked Kelda’s plan, but allowed the sale of Welsh Water to Glas Cymru, a sort of mutual owned by a group of local investors.

Does such a complex experience deserve a favourable verdict? The answer is to be found north of the border, in Scotland. In 1989, Scotland’s water was comparable to the English utilities in every respect, but the government kept it in public hands. For a while, the Scots benefited from lower bills. But as the new Scottish regulator has recently conceded, things look different now. Scottish Water is less efficient than its’ southern peers, its service delivery is poorer and its water quality is worse; it is, in short, ten years behind. To catch up, it is having to raise water tariffs above English levels. The Scots, it turns out, are paying a high price for keeping their water in public hands.

Ocean Thermal Energy Conversion (OTEC)

The total energy available using OTEC systems is one or two orders of magnitude higher than other ocean energy options such as wave power, but the small size of the temperature difference makes energy extraction difficult and expensive. Hence, existing OTEC systems have an overall efficiency of only 1% to 3%.

A unique feature of OTEC is the additional products which can readily be provided: food (aquaculture and agriculture), potable water, air conditioning, and other benefits. In large part, these arise from the pathogen-free, nutrient-rich, deep cold water. OTEC is therefore the basis for a whole family of Deep Ocean Water Applications (DOWA), which can also benefit the cost of generated electricity. Potable water production alone can reduce electrical generating costs by up to one third and is itself in considerable demand in most areas where OTEC can operate. It is estimated that an OTEC device can produce 2,360 m3 of desalinated water per day per MW. Therefore a 50 MW plant could produce 118,000 m3 of desalinated water per day.

Sea water air conditioning (SWAC) is another promising use of DOWA/OTEC. Five such devices are in operation and two are under development. Progressively plants are using deeper sources of water. All work using the following principles:

Water is pumped from a deep cold water source (ocean or lake).

The water is passed through a heat exchanger.

A closed-loop fresh water distribution system is pumped through the heat exchanger cooling the water.

The cooled water is distributed to buildings for air conditioning.

These devices have higher capital costs than conventional air conditioning devices, but lower annual costs. Installations may be eligible for carbon credits as they generally use less energy than conventional air conditioning plants. The amount of credits will depend upon the location and type of installation.

Water Privatisation in Latin America and the Caribbean

Latin America and the Caribbean has been the second largest recipient of foreign PSP for water and sewage sector after East Asia and the Pacific. By the end of 2011 it had received 226 projects worth $30 billion, or 41% of the total global investment in developing countries. The region also had the second greatest number of either cancelled or in distress projects, 28 projects in all, worth $9.0 billion.

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