Development of the Single Global Coal Market

The existence of a single market arose from the growth in seaborne coal trade brought on by the combination of firstly, growth in the demand for coking coal in the 1960s and secondly, sharply rising oil prices during the 1970s. Before 1960, international coal trade had been primarily land based, and been between neighbouring countries. Over one-half of the world’s total trade in 1960 was within Europe and the former Soviet Union. Germany was the major exporter to OECD Europe and Poland, whereas the former Soviet Union was the major supplier to Eastern Europe. There was also considerable coal flow from the US to Canada.

The only significant coal trade was from the US to OECD Europe and from the US to Japan. During the 1960s there was an increasing demand for coking coal in OECD countries with insufficient low cost supplies of their own, resulting in considerable growth in seaborne trade. During the 1970s, newly industrialising countries such in South Korea, Taiwan and Brazil became major importers of coking coal.

The rise of oil prices in 1973 initiated a new phase in international coal trade. The rise provided a strong incentive to convert power stations and other installations from oil; and sometimes from gas to coal. Especially incentivised were those which were initially designed for coal and which had been converted, in the period 1960-1973, to take cheaper heavy fuel oil. The rise also resulted in decisions to construct new coal-fired power plants to use relatively inexpensive imported coal. The trend was reinforced by the oil price increase in 1979, partly because of new coal- fired plants coming on stream, and partly because of the oil product component of the cost of producing and transporting coal. Coal prices peaked in 1982 and then fell over the remainder of the decade. After recovering some ground in 1990, coal prices fell again until 1995.

The Canadian T&D Sector

Canadian utilities are engaged in the North American transition towards competitive markets and are integrated with the American regional systems. The electricity supply industry in Canada is organised on a regional basis. The various utilities, responsible for electricity generation, transmission and distribution in each area, frequently trade power with each other via some of the world’s highest voltage DC transmission lines.

Canadian electricity generation is predominantly hydro-based and is generally cost competitive with other North American jurisdictions. Due to the operations of hydraulic systems, most hydro rich provinces have surplus energy available for domestic and international trade. Canadian legislation requires that exports must be authorised by the NEB and that interested Canadian electricity buyers be provided the opportunity to purchase the electricity, for use in Canada, on similar terms and conditions as the proposed export sale.

The US Federal Energy Regulatory Commission (FERC) is currently planning the creation of regional transmission organisations (RTS) to coordinate transmission systems. The electricity transmission interests in several Canadian provinces are considering membership in RTOs, which are expected to facilitate access by Canadian exporters to US markets and access by Canadians to US supplies. RTO formation could lead to more north-south trade and further integration of US and Canadian electricity markets. To the extent that Canadian competitiveness can be maintained, higher export revenue would result. Market integration could also result in upward price pressure in some provinces.

Due to the increasing interdependence of the networks in both countries, a dependency made clear during the 2003 Northeast blackout, there have been greater efforts to increase cooperation and coordination between Canada and the US. A bilateral commission is planning the formation of the Electric Reliability Organisation, an intergovernmental organisation that would monitor network reliability, settle trans-border disputes, and formulate common industry standards.

The Nuclear power brown-out and renaissance

From the late 1970s to about 2002 the nuclear power industry did not grow but suffered some decline and stagnation and some orders from the 1970s were cancelled. New reactors were few and the number coming on line from mid 1980s little more than matched retirements, though output increased 60% due to improved load factors. The share of nuclear energy in world electricity from the mid 1980s was fairly constant at 16-17%. The uranium price dropped accordingly, also because of an increase in secondary supplies from reprocessing. Some energy companies which had entered the uranium field withdrew and there was a consolidation of uranium producers. The Chernobyl disaster in 1986 had a long lasting effect on several countries politically and socially and changed the world’s population against nuclear power.

By the late 1990s signs of recovery were evident and the first of the third-generation reactors was commissioned, Kashiwazaki-Kariwa 6, a 1,350 MW Advanced BWR, in Japan.

Since 2001 there has been talk about a nuclear revival or renaissance which does imply that the nuclear industry has been in decline for several years. Many factors have combined to revitalise the prospects for nuclear power.

First the scale of increased electricity demand worldwide will strain fossil fuel resources to the limit.

Second is awareness of the importance of energy security. This first became an issue in the 1970s with the oil shocks in the Middle East and has been reinforced in the last two to three years as Russia has used natural gas as a weapon to support increasingly aggressive polices abroad.

Third is the need to limit carbon emissions due to concern about global warming.

However, in Eastern Europe and Asia the nuclear capacity has been expanding, globally, the share of nuclear world electricity has remained constant at around 16% since 1980’s with output from nuclear reactors actually increasing to match the growth in global electricity consumption.

Definitions of Reserves

Since 2006 nearly half of new discoveries have been in deep waters. For example, in 2010 oil discoveries were reported off the coast of Angola, Brazil, Ghana, Norway and in the US Gulf of Mexico, to name a few. Very few large reserves have been discovered in the past ten years.

New discoveries of conventional oil reserves are expected to decline further after their peak in the 1960s. Capacity from conventional fields should decline. Therefore it is most likely that demand will be increasingly met from unconventional oil such as oil share and oil sands. Some industry insiders believe this to be alarmist and are not taking into account new developments in technology and are underestimating the number and size of new discoveries. For example, the biggest announcement in 2011 was Venezuela’s reassessment of its oil reserves to 217 billion barrels. Although, this has not been independently verified and assumed an arbitrary, higher recovery factor. Thus, is in all likelihood on the ambitious side.

However, proven reserves of oil and the R/P ratio, number of years of oil left based on current rate of consumption, for oil has been increasing. The R/P ratio for oil has actual increased. Therefore, it is unlikely that supplies of oil will be running out any time soon. Whether supply can meet demand is another question.

It is clear that there is much confusion throughout the press, investment community and general public about the meaning of the term ‘oil and gas reserves.’ A shorthand definition of reserves means the quantity of oil and gas that can be produced at a profit. Many adjectives are often applied to the term ‘reserves’, such as proved, probable, possible, developed and undeveloped reserves.

Solar Thermal Heat for Water and Buildings

The solar thermal industry has used low-tech technology until relatively recently and been largely concerned with small domestic and building applications for heating space or water, or cooking. However, the industry is now taking a more sophisticated direction and progressing to higher-tech applications involving relatively large electricity generation projects in a number of countries. Some of these schemes have been in existence for a number of years on a trial basis. Solar cooling, although still a very small application with around 80 solar cooling systems in the world is making rapid strides.

Solar thermal collectors are divided into three categories, according to temperature, with low, medium, or high temperature collectors. Low temperature collectors are flat plates generally used to heat swimming pools directly. Medium-temperature collectors are also usually flat plates and are used directly for creating hot water for residential and commercial use. High temperature collectors concentrate sunlight using mirrors or lenses and are generally used for electric power production. These are known as CSP (concentrating solar power) units. In use described as ‘direct’ the solar energy or heat is used to heat water or buildings, or for factory process, and not transformed into electricity.

All technologies operating through solar heating come under the category of solar thermal. These include non-grid solar thermal technologies; water heating systems, solar cookers and solar drying applications etc. These technologies help conserve energy in heating and cooling applications. Solar thermal appliances can be manufactured with a low level of technology and are ideally suited for developing countries. In industrialised countries, solar thermal technology has more advanced applications such as solar thermal building designs. All of these solar thermal devices use heat directly from the sun. They are cheap to manufacture and cost nothing to use.

The more advanced use of solar thermal energy, employing high temperature collectors, involves conversion from heat into secondary energy, electricity. Several technologies have been developed and tested to generate power from solar thermal energy and where some of these technologies are classified as mature, others are in their infancy. Current trends show that two broad pathways have opened up for large-scale delivery of electricity using solar thermal power: ISCC-type hybrid operation of solar collection and heat transfer, combined with a state-of-the-art, combined-cycle gas-fired power plant: Solar-only operation, with increasing use of a storage medium such as molten salt, enabling solar energy collected during the day to be stored and then dispatched when demand requires. Solar thermal power is up to four times as expensive as fossil fuel power.

Electricity Deregulation – An overview

Deregulation and privatisation in the power sector is now reaching a stage around the world when it is possible to discern some patterns and factors emerging, based on experience rather than hypothesis about what ought to happen. Some outcomes have been good but some have been bad, notably in North America, and market liberalisation has advocates and critics.

The momentum towards liberalisation of the electricity supply industry continues around the world but it proceeds at varying paces. As a region, only the EU is moving systematically in a co-ordinated manner, while other markets are developing new structures on an individual country basis. In February 2006 the European Commission published a critical report drawing attention to a number of aspects in which progress towards liberalisation is considered unsatisfactory.

The countries of the EU, with the United Kingdom and Scandinavia at the forefront, have been leaders in creating the sea change which liberalisation of the energy markets is bringing. In July 2007 the final stage was reached for most EU countries in which electricity markets have been fully opened to all customers. A number of countries have negotiated ‘derogations’ in which they have delayed or reduced the scope of the change, due to special circumstances in their markets. One of the main reasons for this is the small size of a market, which only justifies the existence of one generator or very few, thus making competition unfeasible. In practice there are many imperfections in the new European structure, due either to original structural conditions or failures in implementing new rules. The EU Commission has been monitoring progress and is implementing new rules. It may be many years before the optimum situation is reached.

In February 2006, the European Commission published a report in which it analysed and criticised progress toward energy liberalisation in the EU and in which it named specific aspects of electricity and gas compliance with EU Directives. This also applied to the ten Accession States. The problems are not just the result of incomplete implementation of the existing 2003 Directives, but also the result of built-in structural and regulatory problems not yet addressed. Even in member states where the current legislation is being fully implemented, problems remain to be solved.

Natural Gas

Unproved probable reserves

Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.

In general, probable reserves may include (1) reserves anticipated to be proved by normal step-out drilling where sub-surface control is inadequate to classify these reserves as proved, (2) reserves in formations that appear to be productive based on well log characteristics but lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area, (3) incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had been approved at the time of the estimate, (4) reserves attributable to improved recovery methods that have been established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics appear favourable for commercial application, (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the subject area is structurally higher than the proved area, (6) reserves attributable to a future work over, treatment, re-treatment, change of equipment, or other mechanical procedures, where such procedure has not been proved successful in wells which exhibit similar behaviour in analogous reservoirs, and (7) incremental reserves in proved reservoirs where an alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved.

Unproved possible reserves

Possible reserves are those unproved reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves. In this context, when probabilistic methods are used, there should be at least a 10% probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable plus possible reserves. In general, possible reserves may include (1) reserves which, based on geological interpretations, could possibly exist beyond areas classified as probable, (2) reserves in formations that appear to be petroleum bearing based on log and core analysis but may not be productive at commercial rates, (3) incremental reserves attributed to infill drilling that are subject to technical uncertainty, (4) reserves attributed to improved recovery methods when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics are such that a reasonable doubt exists that the project will be commercial, and (5) reserves in an area of the formation that appears to be separated from the proved area by faulting and geological interpretation indicates the subject area is structurally lower than the proved area.

The Natural Gas Industry

It was not that long ago that natural gas was a waste product of the oil industry and flared instead of utilised as an energy source. Interest in natural gas increased as its value as a fuel for power generation and heating was understood. Natural gas is now projected to become the number two fuel in the global energy mix after oil. Not only is it one of the few viable alternatives in the power generation sector to back up intermittent renewables for power generation, but also the use of natural gas in power generation reportedly generates fewer CO2 emissions compared to oil and coal.

Natural gas is also substituting oil in the chemical sector, specifically ethane produced as a by-product in natural gas production for naphtha derived from oil. This is notably in the US where many chemical companies have relocated or announced relocations to sites close to shale gas plays or pipeline infrastructure. For example, Dow Chemical has announced plans to move its chemical industry to the US, but has also announced plans to site a chemical production facility in Jubail Industrial City, Saudi Arabia. This appears to be part of a strategy by countries in the Middle East to produce petrochemicals domestically in order to increase their revenues from hydrocarbons. Some Middle Eastern countries also plan to switch from the use of oil to natural gas for domestic power generation in order to optimise revenue and volume of oil exports.

A similar switch from coal to natural gas for power generation has been reported elsewhere. This is not due to any price advantage for natural gas, as coal is still a cheaper fuel source. Rather the move towards the use of natural gas is to meet carbon emission reduction targets, and because natural gas is a more flexible fuel. This switch has been more notable in the US and Europe to meet energy policy.

NRG Expert Global Natural Gas Report – Market Research

Renewable Energy

Most energy sources can be consumed in two ways, directly and indirectly when converted to another form of energy. For example, wood can be burned directly as a primary energy source to heat space, or it can be burned to produce heat to generate electricity, a secondary energy source. Likewise, geothermal energy can be used directly as heat for industrial process or bathing, and indirectly to generate electricity. This article examines both uses but focuses mostly on indirect use for generating electricity and to a lesser extent liquid or gas fuels.

Some energy sources, such as hydro or wind power are mostly used to generate electricity but they can be used directly, as both sources have been used to raise water for irrigation. It is important to bear these distinctions in mind because the profiles of primary and secondary use of renewable energy are quite different. For example, renewables account for 12.8% of global energy supply, after fossil fuels, and biomass and combustible waste account for nearly 80% of primary renewable energy. Most consumption of primary renewable energy is of traditional fuels in developing countries, such as wood or animal dung. However, the generation of electricity, a secondary energy source, presents quite a different picture. Renewables account for 18.5% of total electricity generation. Hydro power accounts for 86% of renewables’ share of electricity production and biomass for only 6%.

Total renewables supply experienced an annual growth of 1.9% over the last 18 years, identical to the annual growth in TPES (Total Primary Energy Supply). However, the ‘new renewables’ such as solar photovoltaic and wind power have recorded a much higher annual growth of 42.5% and 25.1% respectively. Other renewables reporting growth above average include biogas (15.4%), liquid biomass (12.1%), solar thermal (10.1%), geothermal (3.1%) and hydro (2.3%).

The Economics of Nuclear Power

There are many uncertainties about the economics of future nuclear generation. These are aggravated when nuclear is compared with other sources of power, because these are subject to their own uncertainties, such as fuel price rises and political manipulation such as OPEC and recent Russian gas manoeuvres. The cost of building nuclear power stations was initially very high but some countries are now building enough to develop standardised designs and blueprints which have reduced costs dramatically.

Many reports have been released in the last three years assessing power generation costs. These show a wide range of estimates of the cost of nuclear generation and alternative sources of power. The highest cost calculated is 67% higher than the lowest. Among these reports, an MIT study puts nuclear power as the most expensive of the base load sources, a Royal Academy of Engineering study as one of the cheapest among both base load and renewables, and the cheapest depending on several variations of input.

Nuclear power is a base load generating resource, unlike most renewables Its fuel source, uranium, is plentiful and secure compared with imported fossil fuels It is free of GHG emissions
The report by MIT is concerned with base load power and confines itself to a comparison of nuclear power with coal and gas. It acknowledges the cost of carbon and cites various alternatives. The RAYENG study includes the non-base load renewable technologies and evaluates nuclear, fossil fuel and renewable power, together with the cost of carbon abatement for fossil fuels and for standby generation for back up of intermittent sources.

The NERA report draws on the excellent work of the other institutes and pulls them together. It identifies a number of factors which are leading to improved prospects for nuclear power: Fossil fuel prices, especially for oil and natural gas, have continued to rise and are currently at high levels.

The industrialised countries are becoming more dependent on imported gas and oil and self-sufficiency is coming to an end, combined with concerns about the long-term reliability of major overseas sources of supply
Costs for nuclear plant could be kept down by streamlining the permitting process and keeping to construction schedules.
Nuclear investment has therefore become a reality again, and this is fuelling a revival.