Energy - The Global Outlook
Are oil and gas reserves running out? Should companies and individuals invest in energy companies? Is there a future for traditional sources of energy?
What about new energy sources - how important are they and can they overtake or replace traditional energy sources?
How will rises in energy prices affect householders and companies? The answers to these and more are covered in a wide-ranging survey of the global outlook for energy.
There follows a series of articles on the global outlook for energy.
- Is Oil Running Out?
- Is Gas Running Out?
- Is the Oil and Gas Business a Good Investment?
- Is Coal a Good Investment?
- What about nuclear?
- What about renewables?
- Will the global economy require more energy in the future?
- Where will we get our energy from in the future to satisfy the anticipated demand?
- What’s all the fuss about with regard to the threat of electricity black-outs in Europe and USA?
- What will happen to oil production in Iraq?
- Will Russia go on increasing oil production?
- Where are the opportunities to increase oil production?
- How important is oil exploration – will it have an impact?
- What new technologies are there that will increase recovery factors further?
- What is primary, secondary and tertiary oil recovery?
- What is the future for Oil Sands?
- What about Oil Shales?
- How is recovery in gas reservoirs increased?
- Is the oil price high?
- What oil price should I expect based on the economic and political forces acting?
- What are the key threats that could cause oil prices to rise further?
- Why do we have refinery difficulties? What is the outlook for refining?
- What’s the outlook for coal – is it a good investment?
- How does Hydrogen energy work?
- What will the impact of Hydrogen economy be?
Not really – on current projections, there will be enough oil for at least another 50 years though the cost of extraction will likely rise as more of the low cost oil has been extracted. This is predicted even though oil demand is projected to double in the next 20 years. Oil prices over $15/bbl make oil sands economically attractive – there are huge quantities of such reserves in Canada and elsewhere. Global reserves have replaced product for the last few years.
The key issue though is likely to be expanding the global production capacity to meet the rising oil demand. Some $1 trillion of investment is required to expand capacity from the current 70 million barrels a day, to 150 million barrel per day by 2020. Much of this investment is in countries with high political risk – with state run enterprises.
Many of the countries such as Saudi Arabia have expanding populations, high local expectations with regard to social welfare - increasingly governments will be strapped for cash as they pay for the social costs of the expanding population whilst having to pay for production capacity and infra-structure upgrades. Because most of the Middle East reserves are likely to stay in the full control of state run oil companies and governments, with fairly minimal International Oil Company (IOC) involvement – it will make such capital investment difficult and hence there is likely to be future supply shortages as OPEC (Organization of Petroleum Exporting Countries) falls behind demand increases.
This is particularly so since capital intensive oil development in risky, and such countries are considered less attractive to the global investment markets.The financial markets also do not like the long lead times, uncertainty in oil price and risk of assets being seized, political instability or contractual terms changed.
Even though oil production is very profitable, the size of investment and risks have driven many investors into higher return, less capital intensive and lower risk service businesses in developed countries or the fast developing economies of China, India and the rest of Asia Pacific.
No. There are huge gas reserves which are likely to last some 100-200 years. Russia, Iran and Qatar in particular have huge reserves. Low cost gas close to high population centres – e.g. in the USA and North Sea, are in significant decline. We will increasingly become more reliant on imported gas from greater distances – e.g. Russian gas into Western Europe and Canadian gas and LNG (Liquified Natural Gas) into the USA.
Indeed, the LNG business will likely see a huge expansion – with more LNG coming from Qatar, Australia, Nigeria and Indonesia – with demand rapidly rising in particular in China and the Far East, India and the Middle East. The huge up-front capital investments required for LNG plants will create demands for both the IOCs and National Oil Companies (NOCs) / governments. The gas business is likely to remain a profitable business, albeit with risks related to the long term investment
It depends. If you invest in the stock market, share prices can go up or down. The same applies for buying oil and gas shares. The smaller companies are particularly volatile – announcement of a new discovery can triple the share price of a small oil exploration company. Announcement of a dry appraisal well can halve the price.
The larger integrated oil companies have higher dividends, more stable cashflow and longer term projects. This degree of stability makes these shares more popular with investment fund managers, along with the fact many of these companies are part of either the New York Dow Jones or the London FT100 indexes.
In the longer run, the large companies will find it increasingly difficult to replace existing oil reserves. Meanwhile, the National Oil Companies in the Middle East, Russia and elsewhere are getting a larger proportion of oil reserves and production – their skills, expertise and use of technology and contractor services are all improving, making them less reliant on International Oil Companies (IOCs) expertise.
That said, the deals being done by the IOCs are generally attractive and the longer term cash-flows seem secure as long as oil prices stay above say $25/bbl – which seems highly likely. Purchase of IOC stock also provides a hedge against high energy prices – which can lead to higher inflation, interest rates and lower global growth for other businesses.
The alternatives to oil such as renewables and hydrogen are not being developed with any real vigour – hence oil is likely to remain a very important part of global economies for the foreseeable future. In any case, most IOCs are exposed to alternatives energy sources and therefore could shift rapidly into these markets if a change in energy usage occurred quickly.
Some of these companies have patents on Hydrogen and Fuel Cell technologies – which would become very valuable if automobiles converted quickly to such technologies.
The price of coal has doubled from end 2003 to end 2004 – and is likely to rise further in the future. The massive increase in demand for electricity in developing countries such as China and India is driving up the demand for coal.
Both India and China have large quantities of low cost coal – which will increasingly be used for electricity generation. Interestingly, the USA has the highest coal reserves in the world – with vast reserves of high grade anthracite in Wyoming. Some open cast seams are up to 100m thick. In energy equivalent terms, the USA has the largest energy reserves in the world – it is just that much of this is coal.
The “dash-for-gas” has subsided in the USA because gas prices have been driven up by high demand, Canadian imports, no big gas reserves additions in the USA and lack of spare capacity. A similar situation has occurred in NW Europe. Increasingly LNG imports are seen as necessary to supplement pipeline gas imports.
Coal is attractive in that it is not volatile, open cast extraction is low risk and there are plentiful supplies. However, the downside is the high levels of CO2 emissions, particulate pollution in non clean burning power plants and high overland transport costs. Coal is likely to become an increasingly attractive energy option for those countries that are not signed up to the Kyoto protocol.
The impact of global warming and its links to CO2 emissions – produced by fossil fuels and coal might curtail this growth – but this depends on environmental pressures, commitment to the Kyoto accord and confirming the link between global warming and CO2 emissions. The pressures to provide an economically sustainable future for the huge populations of India and China are likely to lead these countries to expand coal production to provide energy for industrial expansion and economic growth.
The use of coal in the USA will be driven by declining oil and gas reserves, lack of economic alternatives, fears over nuclear power safety and reliance on expensive oil imports from insecure sources. Oil will be used to fuel automobiles whilst coal will increasingly be relied on to produce electricity.
Yes – most definitely. Oil demand is projected to increase from 70 million barrels a day to 150 million barrels a day by 2020. The number of automobiles globally will double – many of these will be in China and India. Gas demand will sky-rocket in Asia Pacific. Coal demand will increase significantly.
The increasing global GDP and population with ever increasing expectations of wealth and lifestyle are likely to mean a rapid expansion in energy supplies of all types being required to keep pace. To put this into perspective, China’s GDP will likely be larger than the USA by 2040. Imagine 1.5 million people in China and 1 million people in India having the ability to purchase an automobile, have air conditioning and central heating and the myriad of electrical appliances available on the market.
Even if there was no growth in automobile demand in developed countries in NW Europe, Japan and USA, there would still be a significant expansion in the requirement for oil. The only way this would change is if either hybrid gasoline-electric automobiles and/or hydrogen fuel cell or natural gas powered automobiles became popular.
For reasons that are difficult to explain, there has been very little technological progress on the fundamentals of automobile power (by the internal combustion engine) in 80 years. We are still fuelled by gasoline powered by internal combustion via vertically moving pistons in a very inefficient process that wastes much energy via breaking, idling and lack of recycling of energy from waste hot water, kinetic energy, pressure and the like.
Without tax incentives, customers are likely to choose gasoline powered vehicles for the next few years. The question is – will they switch rapidly to hybrid-electric or hydrogen if automobile manufactures market these options more aggressively? Will the take-up be rapid like the mobile phone or internet? It will probably take a proper oil crisis to kick these alternatives in – if/when this happens, some time in the next 20 years – there could be a big shift from gasoline to electric.
That said, we will still need to have fuels to generate the electricity and produce hydrogen – so oil demand might not grow as fast as predicted because of this, but we will still need coal, gas, renewables or nuclear in its place. Unless we “un-invent” the automobile or something totally unexpected happens – overall energy demand will rise dramatically in the next 30 years.
Not sure. The Nuclear debate is hotting up – with most environmental groups opposing it and many western governments distancing themselves from the debate.
A few learned environmentalists have now come out in favour of Nuclear power because the CO2 emissions are very low as well as particulate and sooty pollution. The process is very efficient – but the industry has been plagued by Nuclear scares and crises – such as the partial melt down at Chernobyl. More recently the nuclear safety cover-up in Japan did not help confidence in safety – and the high decommissioning costs and nuclear waste disposal are highly problematical.
Countries such as France and Finland have produced vast quantities of nuclear power safely and efficiently – indeed, France exports much of it. In Finland, the government and public had a mature debate for many years before deciding collectively to proceed ahead apace – it was considered the best sustainable option.
Meanwhile, populations close to Chernobyl are still affected by the disaster and views in many countries are polarised. Expect the debate to continue – with some countries expanding and some countries decommissioning, depending on the political situation, and environmental and economic pressures.
Renewable energy is likely to become increasingly important – that said, the size of investment required to make a significant dent in the overall energy demand seems prohibitive. Most renewable energy sources were invented many years ago – but costs have not come down enough to make them viable economically without subsidies.
Wind energy is capital intensive – the most efficient windy areas are normally in the remoter regions away from big population centres. The added costs of expanding transmission over land, and energy losses during transmission make the economics worse. In addition, cold snaps and heat waves normally correspond to periods of very little wind – so full non-wind installed electric capacity is still required. Some countries such as Denmark generate a large proportion of their average electricity via wind energy (25%) – though in Denmark’s case they can get swing electricity capacity during cold snaps from neighbouring Germany. Many people object strongly to wind energy because they believe they are a visual eye-sore in the countryside – some people complain that offshore wind farms represent a hazard to shipping.
Solar is most efficient in sunny counties – however, much of the largest populations where electricity demand is highest reside in less sunny climates (e.g. NW Europe, Japan, Korea, NE USA, NE China). Furthermore, solar is not much use on a cold winter’s day in the higher latitudes. Solar is quite expensive – large plant is required with land and/or owned buildings. Solar does seem a good source to supplement domestic energy requirements – for heating and cooling – though capital costs are high and most people prefer not to risk such investment when they might move home in the next year or so and get little return on their investment. Without significant tax breaks or grants – the use of domestic solar power is unlikely to increase dramatically.
Heat Pumps – this method of supplying heat from underground pipes is quite effective and efficient, but again the capital cost for many people is prohibitive. The question is – should one invest say $7000 on the equipment when you might move house before it pays for itself in say 7 years. Most people choose to spend or invest their money on other items.
Hydro-electric – most of the possible hydro-electric power projects were built between 1955 and 1985. Projects have dried up because of environmental concerns from flooding valleys along with altering the hydrological environment. Norway is one of the biggest producers of hydro-electric power – most of these were built many years ago before environmental constraints were tightened, and the projects are very efficient because of the steep mountain slopes and high rainfall.
An increasing amount of energy will come from long distance imported pipeline gas and imported LNG shipped from other global regions. Oil production in the Middle East will be expanded and an increasing reliance on OPEC along with Russian oil will become the norm.
Coal production is likely to be expanded – particularly in India, Bangladesh, USA and China. Renewable electric supply will be increased through solar in sunny populated regions (e.g. Florida, California, Spain) and wind ( UK, Holland, Denmark, parts of the USA). Nuclear supply may expand in some countries such as Japan and France – but this will depend on the individual countries energy strategies, suitable investment and mitigating environmental and safety concerns.
There is a possibility that Hydrogen and the use of hybrid gasoline-electric automobiles will decrease the dependence on imported Middle East crude oil – but this is most uncertain. The days of low cost energy – from 1986 until 2002 are likely to be over for good. Commodities prices have approximately doubled for gas, electricity, oil and coal in the developed world in the last 2-3 years.
It seems likely that oil prices will stay above $30 per barrel and possibly head well above $50 per barrel depending on global security tensions, oil worker strikes, supply disruptions and the ability of OPEC producers to expand supply to meet demand.
The price of oil in real terms at $50 per barrel is still well under the $85 per barrel in 1980. In UK pound sterling terms, the price of oil would need to be over $110 per barrel to be equivalent to the 1980 peak oil price. Furthermore the global economy is far less sensitive to oil prices since industry is less energy intensive and the cost of importing energy is less of a proportional cost when compared to GDP than in the 1970s and 1980s.
Gas has replaced much of oil usage. However, because global investment markets are so sensitive to the threat of inflation, and each $10 per barrel increase in oil prices is thought to add about 0.2% to inflation – the financial markets are deeply concerned about increasing oil and energy prices. To sustain high growth and low unemployment – global markets need low energy costs.
It seems that anything below say $40 per barrel, industries can largely absorb the additional costs with without passing much of the cost to the customer. But over $50 per barrel – manufacturers and heavier industries feel squeezed and the financial services industries feel the pressure through lack of consumer confidence and investor nervousness. The oil price has risen dramatically – but whether it is high is subject to much debate. Oil prices have probably been too low for too long.
Investment in electric power generation has trailed well below the increase in GDP in most developed countries. Some reasons for this include de-regulation of electricity markets and privatisation which has caused electricity producers to run with lower spare capacity than previously. Furthermore, low electricity prices caused by the increased competition and lack of demand between 1998 and 2003 in many developed countries did not stimulate investment in new power generation.
The growth in electricity demand in 2003-2004 through a fairly strong economic growth period has caused far higher electricity prices, a shortage of spare capacity and the occasional electricity black-out (e.g. NE USA, Italy in 2002/3).
These supply disruptions have occurred when a surge in demand has tripped power plants. Many electricity experts expect significant problems in NW Europe and USA in the winters of 2004/2005 – particularly if there is a cold snap.
Swing capacity and the increasing reliance on imported electricity from overloaded electricity grids is anticipated to create disruptions in the future. If industry is disrupted for prolonged periods it can have an impact on GDP and investor confidence, as happened in the NE USA end 2002.
One of the underlying causes of the lack of capacity is – again – the capital intensive nature of the business, long investment time frame, low returns on investment and competition from lower capital intensity / higher margin investments – e.g. financial services, real estate, retail.
Many investors view the electricity business as an old low-return (utilitarian) capital intensive business – and government have provided little incentive to invest in these large infra-structure upgrades. Meanwhile, shareholders pressurise management to reduce capital investment and increase returns and dividends. Uncertainties in demand requirements in the future have not helped planning infra-structure upgrades.
Gas to liquids is the conversion of natural gas (methane) to gasoline (petrol). The process is not new – indeed since the 1980s a gas to liquids plant in Bintulu Malaysia has been producing some 15,000 barrels a day.
Unit technical costs – the cost per barrel to produce this form of fuel, has been some $15 per barrel, rendering the process only marginally economic until recently. In the last few years, the large IOCs have announced joint venture deals in Qatar to produce three new plants totalling some 300,000 barrels of production to be built in the next ten years.
The process takes natural gas and by chilling/condensing, produces high quality gasoline and distilled water as a by-product. Each 100,000 barrel per day plant costs over $1.5 billion - the process is very capital intensive, and plants take five years to plan and built.
In Qatar, there is an almost endless supply of low cost natural gas from the North Field which straddles Qatar and Iran and is of unknown extent. Only part of this giant gas field is developed, so in theory, the gas to liquids plant could be expanded to dramatically increase Qatar’s oil (and gas) production, particularly if prices stay above $30 per barrel.
The liquid gasoline is shipped by tanker to the many markets that require the refined fuel. Because the fuel is ultra-clean and high quality, its market is strong in countries where low sulphur and clean-burn gasoline is required through environmental regulation. It also gives an opportunity to monetise stranded gas in remote land-locked locations – such as Turkmenistan, since the refined fuel can be shipped via pipeline and barge.
LNG as a form of energy supply and investment has a very bright future. Gas is produced through the normal process of extraction via gas wells and piped via a gas plant that processes the gas and knocks the water out (dehrydration).
The gas then passes into an Liquified Natural Gas (LNG) Plant where the gas is super-cooled and condensed into a liquid. It is then pumped into chilled pressurised tanks on LNG ships and transported to a gas market – often many thousands of miles away. The LNG then passes into a de-gassing plant where the gas pressure is dropped and the gas is warmed – then fed into the gas pipeline system to supply industrial and domestic customers.
To make this whole process economic, the gas needs to be low cost to extract in the first place – typically 50 cents or less per standard cubic foot. The LNG process often costs about 50 cents, with transportation 25-50 cents, degassing 25 cents, and pipeline transport to customer say 15 cents. So typically gas prices for the customer need to be at least $1.65 to make this process economic. Until recently, gas prices in the USA and Europe were only $1.50-$2.00 but recently gas prices have risen to over $4 making LNG economic to import to NW Europe and USA.
Because typical integrated LNG plants with gas development and shipping typically cost between $4 and $12 billion to build – the low gas price and saturated market has until recently put many investing energy companies off. However, LNG in the last few years is expanding dramatically since energy companies can see a long term high gas price and massive future gas growth and requirement for China, India and to a lesser extent USA and NW Europe.
Because of this, Qatar, Indonesia, Venezuela, Nigeria, Australia, Oman, Trinidad and Malaysia are either expanding their LNG production or about to do so.
Because of the technological expertise, marketing requirements and capital requirement, the larger IOCs are still able to get large equity stakes in such joint venture schemes. The technology is not new, LNG has been produced since the early 1970s – but the LNG trains are now some 5-10 times bigger than the ones built 35 years ago. The economies of scale and lower unit costs have made LNG more economic and opened up LNG shipping to ever longer distances (e.g. eastern Russia to western USA, NW Australia to western USA, Qatar to Japan, Nigeria to Spain and southern USA).
IOCs with the biggest capital LNG exposure are Shell, ExxonMobil, BP, Total, ChevTex and BG. NOCs with the biggest capital exposure to LNG include Petronas, Pertimina, Qatar National Oil Company, Oman LNG and the Nigerian National Petroleum Corporation. In Japan, Mitsubishi and Matsui are both large investors in LNG processing and shipment.
It is envisaged that increasing environmental concerns with pressure to lower CO2 emissions and use of cleaner burning fuels will drive LNG demand upwards. The security of supply and long term contracts is also attractive to many large customers. Spot cargos are also commonly available. The gas can be used in power stations – and replace coal (which produces higher CO2 emissions and particulate pollution).
Big new markets are China and to a lesser extent India (as a replacement for some coal, and providing domestic consumers with gas for the first time) and USA and NW Europe (replacing pipeline gas because indigenous gas reserves are in decline).
This is very uncertain. Iraq is currently producing some 1.8 million barrels per day. The country has oil reserves of about 112 billion barrels, second only to Saudi Arabia. With a standard depletion rate of 5% - this implies that the sustainable plateau production rate should be 6.6 million barrels a day. Clearly there is a long way to go.
The security concerns and lack of investment capital to expand infra-structure are key concerns. How long it will take to boost oil production is most uncertain and depends on stability. If things are highly unstable, production could stay at current levels for a long time.
If stability is restored and investment attracted, rates could rise to say 5 million barrels a day within 10 years. However, this would require some $80 billion of investment. With no guarantees on oil price, stability and security, it seems highly unlikely that such capital would be invested and the most likely outcome is a rise to double the current rate by say 2008 with more minimal investment and infra-structure refurbishment.
Russia has raised oil production from some 4 million to 8.5 million barrels per day in the last 8 years. After the collapse of the Soviet Union – the oil fields fell into decline in part because this coincided with low oil prices and high pipeline tariffs.
In the last five years, better management of the pipeline infra-structure, reducing pipeline tariffs and a big injection of both the latest subsurface technologies and capital has dramatically increased oil production. However, the “easy wins” have been had and it will be increasingly difficult to sustain such rates moving forwards.
As water production increases and the fields become more mature, more drilling, water injection / secondary recovery will be required to sustain the rates. One would expect rates to stabilise at around 8.5 million barrels a day but not rise significantly higher. Drilling and development activity levels will likely remain high to sustain such production rates.
In the 1970s, close spaced 2D seismic data/interpretation and water injection boosted production rates and recovery factors. In the 1980s – it was offshore technology, 3D seismic data/interpretation which boosted rates. In the 1990s it was horizontal drilling technology, electrical submersible pumps and deepwater / sub-sea technology.
The problem this decade is, there is no big new technology that is likely to have such an impact as the technologies that were implemented in the 1970s-1990s. Enhanced 3D and 4D seismic, ultra-deepwater, remote operations technology will only provide incremental gains in the most demanding environments.
For many IOCs, all the good technology that was developed and implemented in the last 30 years has accelerated oil production and increase recovery factors from some 20-30% to up to 60% - but this will also cause higher decline rates and IOCs have to work harder and faster to stop this decline.
Access by IOCs to new oil reserves is becoming increasingly difficult because the bulk of the remaining oil reserves are governed by state oil companies, many of whom feel they do not need a lot of help. This is not likely to change since these companies can buy in the technologies and expertise from contractors to increase recovery factors and production rates. The nationals have to a large extent trained themselves up to manage the fields in most mature developing provinces.
There is no particularly exciting new technology that will have the impact that either deepwater, horizontal wells and/or 3D seismic has on recovery factors or production rates. The IOCs are “at the top of the creaming curve” whilst the NOCs in OPEC countries have most of the remaining opportunities and optimisation to boost recovery factors.
Primary oil recovery is the recovery of oil through normal drilling and production depletion. Commonly, vertical and horizontal oil production wells are drilled to depths of 500 to 5000 metres and are cased with pipe cemented in place. Pumps are installed – either beam pumps (“nodding donkeys”), electrical submersible pumps, gas lift completions or normal depletion completions. The wells are then bought on stream and produce until the reservoir pressure drops to a low level. Sometimes, pressure is maintained naturally by “natural water drive” where an influx of water from adjacent reservoir rocks keeps the pressure up – this can lead to high and sustained production rates until water breaks through, thence the wells will common water out very quickly.
Where no natural water drive exists, wells will normally produce until the pressure declines to a fairly low level. If only low levels of water are being produced with the oil at this stage, then water injection wells are drilled and water injected – to boost the reservoir pressure back up – this is termed secondary oil recovery – the injection of water and/or gas into oil reservoirs to boost pressures and/or increase oil sweep efficiencies. The process can start immediately after first production, but normally is implement some years after start-up – hence the term, secondary oil recovery. Tow main types of water injection occur - water injection in a grid pattern called “pattern flood” in complex reservoirs with poor lateral communication or wells drilled on the flanks of the field called “edge water injection” – normally in simpler sandstone and carbonate reservoirs with good communication. Such water injection can sometimes increase recovery factors by double (say 15% to 30%, or 30% to 60%).
Missible gas injection is a process of injecting natural gas or carbon dioxide which that then percolates through the reservoir, thereby increasing the sweep efficiency and recovery factor. This process is far less common than water injection.
Tertiary oil recovery is a third stage. The two main types of process are steam injection and chemical injection. Steam injection is far more common and consists of injecting super-heated water in the form of steam down wells which then floods through heavy oil accumulations – thereby heating up the reservoir, reducing the viscosity of the heavy oil and increasing the production rates along with the recovery factor. The process often has relatively high unit technical costs of $10-$14 per barrel to produce such tertiary oil – because of the high capital and operating costs of the steam plants, infra-structure and closely spaced production wells. As long as the heavy oil accumulation is relatively large and shallow with high permeability, if the oil price is over $20 per barrel, economics are often attractive. Good examples of successful heavy oil steam injection developments come from Venezuela and USA ( California). Projects slated for development include fields in Oman, Holland and Iran. The projects rely on excellence in reservoir surveillance - monitoring the data and acting appropriately on the results. The process is labour, capital and operating cost intensive – some companies have a niche in these activities and are rewarded handsomely for their efforts at prices over $20 per barrel.
Chemical injection was tried in the early 1980s – it normally involves pumping polymer into a depleted, highly permeable and medium-light oil reservoir. The polymer is flushed through and picks up residual oil – which is then extracted from the polymer at the surface. The polymer is then recycled/cleaned, dehydrated and re-injected again. The process is very expensive – costing some $30 per barrel and is technically challenging and resource intensive. In summary – there are far easier ways of obtaining oil at lower costs – few if any projects are proceeding, despite the high oil prices. Many petroleum engineers were disappointed with results years ago – and there is not much evidence things have changed since the early 1980s.
Good. Large Oil Sands accumulations occur in Canada. These thick oily sands are mined in huge open cast quarries, by diggers with buckets the size of a detached house. The rock is then pulverised, and heated in large processing plants. The oil is then driven out from the rock and separated – then refined into cleaner oil products. The processed rock is then transported back to the quarry and tipped as back-fill. Eventually the quarry is grassed over and more or less returned to its original condition (grassland or forest). There is a very successful and economic project in Alabasca Canada that has been producing some 150,000 barrels a day since 2001. Oil prices need to be over about $13 per barrel to make such projects economic. Significant capacity expansion is possible in such low risk projects – albeit capital intensity is high – requiring some $3 billion for 150,000 barrels per day production. It seems likely that such projects will expand because of security of supply issues for North America. Interestingly, the projects provide a lot of income and employment for the local populations – and environmental concerns have been addressed with the regional and local governments allowing such projects to proceed, on the basis that the quarries will be returned to their natural habitat after extraction. Such projects are easier in remote barren areas where local employment is required, and quarries can be returned quickly to their original environment.
Oil Shales are fissile mudstones that have high total organic carbon content (typically 20-30%) bound up in the rock. There are a few ways to extract such oil – one is by very closely spaced shallow wells with heaters that cook the total rock area up – wells in between extract oil that migrates out. This is a very energy intensive and expensive operation – currently considered uneconomic by most energy companies. Another method is to quarry the oil shale, pulverise the rock, cook the rock and extract hydrocarbons. Again, this is a very energy intensive and costly operation – currently considered either margin or uneconomic. There are simpler ways to extract oil than mine or cook oil shales – and the process requires a big electricity infra-structure and operating expense to extract the oil.
Most gas reservoir produce by normal depletion. This is the decline in pressure from the original reservoir pressure (say 300 bars) to abandonment pressure (say 50 bars). The pressures over the production life of the field will often show a straight line decline. However, if water starts to ingress – this will support pressures and normally keep the production rates higher for longer. However, if water then reaches the well bore, these gas well often decline and flood, or die quickly – through liquid loading of the wellbore. Increasing the density of well might increase recovery factors a little – but in permeable reservoirs, additional producing wells are drilled primarily to increase production rates or off-take. If the gas field does not have a water production problem and is relatively large, it is often economic to build gas compression. This allows gas to be produced to very low pressures – say 5 bars, thence it is compressed to say 25 bars and exported via the gas pipeline infra-structure. Most large gas fields have gas compression installed in later field life – this can often increase recovery factors by some 10-15%. Because gas flows more efficiently through sandstone and carbonate when compared to oil and leaves less residual gas saturations within the reservoirs – recovery factors can be as high as 95%, typically 75-90%. In oil reservoirs with secondary water or gas injection, recovery factors are typically 40-65%.
Most of the oil reserves and major oil producing basins have now been discovered and developed. There are few virgin oil exploration areas with a lot of potential – almost all have been drilled. There is a process of creaming – through additional exploration and appraisal drilling and implementation of new technologies. In summary, it is likely that additional exploration will not markedly change the global oil reserves picture in the next 50 years. Most reserves additions are made from existing producing oil fields – this has been the case for the last 15 years. Even when the small independent oil exploration companies strike oil, the accumulations do not make a significant difference to the global reserves picture. An example is the Cairn 2004 discoveries in India which – if they add 300 million barrels – only account for some 5 days of global oil production. That said, these discoveries have a big impact on the value of these oil companies and on the economics of countries where they are discovered, particularly if the country has a small oil reserves base.
Most of the OPEC oil producing countries have rapidly expanding and relatively young populations with increasing requirements for governments to provide social welfare – in part to maintain stability. These costs are rising annually which means the OPEC producing countries probably prefer to keep prices fairly high. This global economic process transfers wealth from the non producing developed (wealthy) countries to the OPEC producing and developing nations. However, OPEC will likely not want oil prices to rise too high since this will stimulate the advancement and uptake of alternative energy sources – which could cause the oil price to crash and reserves to be devalued. This would also impact their financial situation with regard to banks and inward investment.
Meanwhile, the USA would like to see stability in the Middle East – so higher oil prices over $25 in 2002 initially did not cause any real concern. However, high oil prices act like a tax – and have the affect of stifling economic growth. Initially there was a big concern that inflationary pressures would kick in when prices rose above $45 per barrel. This has so far not happened, though the higher oil price spooked the financial markets for a few months. Meanwhile, the decline in the US Dollar against the Euro and Yen has meant the positive impact for the OPEC countries is not as large as it would otherwise have been. This has also softened the impact of high oil prices in Europe – because of the high Euro value. In view of the projected increase in oil and energy demand, one train of thought is that a higher oil price will stimulate the required investment to expand production capacity – otherwise there could be a big price spike in the future if demand outstripped supply capacity. So it seems that oil prices in he range of $35-50 per barrel are a range that both OPEC and the USA and other developed nations can accept. However, the biggest impact of such higher prices are on developing countries with no oil production – e.g. most African countries, many countries in South and Central America – particularly those countries without coal or gas and high and increasing populations. This “tax” on their economies will stifle their GDP growth and lead to tough conditions for these populations and governments – one reason why foreign aid is so important and will probably become more so in future.
There are many of these. Examples in the last year have included terrorism, strikes by oil workers, hurricanes, cold snaps, heat waves, supply disruptions due to cold weather, political turmoil in oil producing countries, explosions at oil refineries and oil installations, comments on the lack of available spare production capacity, and tensions between different countries. In 2005 and onwards, any indication that the production capacity increase is not keeping pace with demand increase will lead to prices firming. Any news indicating the Saudi Arabia or other OPEC countries are being too optimistic in their forecasts for oil production growth, reserves or forecast and actual field decline rates might also support prices. Hording of oil by China and the USA – into strategic reserves might also support prices. There seems to be a say $5-$8 tension/security premium built into prices at present – this could increase if tensions increase. Much will depend on what happens in the elections in Iraq and security within the country.
Projections of oil production expansion in many of the OPEC and Non OPEC countries seem optimistic – too many mature oil producing countries have projected growing oil production over the next 15 years. If the expected capacity expansion does not materialise and/or reserves are lower than forecast, other forms of energy such as coal and gas production will need supplement energy requirements – but with the projected rapid expansion of automobile use in China, India and to a lesser extent the rest of Asia Pacific and North America and very little up-take in hybrid petrol-electric usage, is seems supply and demand are finely balanced and it would not take too many issues to put a lot of pressure on prices.
In a 6-12 month time frame, Saudi Arabia is likely to be able to increase its production from 9 million to 10 million barrels. The UAE has probably got an extra 300,000 barrels of spare capacity – but that’s it. Much relies on the production expansion effort in Iraq – can rates increase from 1.8 to say 3 million per barrels in the next 12-18 months? It seems rather optimistic. Meanwhile, if global GDP growth is close to the 4% projected for 2005 and China continues it’s massive and increasing appetite for oil consumption, then a supply crunch might occur. The situation in 2004 has not been helped by speculators piling into the market driving prices up and betting against the calming words of OPEC spokespersons. How much of this speculation is because investors see a short term money making opportunity and no better investment opportunity elsewhere in stocks, gold or bonds is an interesting debating point. New oil production from West Africa will not make a big difference and has already been largely factored into forecasts. The offshore US and North Sea production is in fairly steep decline – adding further pressure on prices. A compounding and important factor in high gasoline prices in the USA has been the complexity and high specifications of fuels and gasoline’s because of new environmental and fuel quality legislation.
Gasoline prices in the USA have risen dramatically in 2004 – mainly because of the increased price of crude oil, but also because of the new variety of high quality clean fuels required in different states and the complexity of getting the right fuels in the rights place at the right time. Meanwhile, oil refineries have been processing at close to maximum capacity. There is little spare capacity left – the main reason for this is because of the lack of investment in oil refineries in the last 15 years. Increased environmental legislation, and clean-up costs, plus the threat of litigation and issues from environmental legacies and liabilities have put a damper on refinery investments. Furthermore, a prolonged period of low refining margins due to overcapacity in the late 1990s meant many of the smaller less efficient refineries were closed. The increase in US demand driven by the strong economy in the last few years has surprised many. Again, the refinery business is very capital intensive with long lead times and uncertain future margins and capacity requirements. Refineries are finally making good returns – but how long this will last is debatable and uncertain. Until stability and the longer term economic outlook indicate sustained higher returns, it seems likely that investors will turn their backs on refinery investments. Furthermore, environmental pressures make it almost impossible to build new refineries on Greenfield sites in developed countries. Increasingly – countries with stringent environmental regulations that stifle refining capacity expansion might have to rely on imported refined products at a higher cost. The lack of refinery investment and increasing demand is likely to keep refinery margins relatively high for the foreseeable future – particularly in Asia Pacific and North America.
Coal prices have doubled in 2004. The increase in oil and gas prices will almost certainly have the knock-on impact of increasing demand for coal – particularly in countries that either do not support the Kyoto accord or have a lot of leeway within these environmental constraints. New coal discoveries in Bangladesh, increasing production on India, China and expansion of coal production in Wyoming in the USA all provide interesting investment options for energy investors. The use of coal in the newest cleaner-burning coal fired power stations should stimulate demand for coal, particularly the less polluting high grade (low sulphur) anthracite. Wyoming open cast coal mining is flourishing – and with the USA keen to develop indigenous energy sources to mitigate their reliance on imported energy, the long term economic future for such high grade open cast coal mining close to markets or power stations seems very good. However, underground shaft coal mining in all but the most prolific areas seems in terminal decline – because of the high cost, complexity, labour intensity and safety. Open cast mining of lower quality brown coal of large size with economies of scale should also thrive if environmental concerns of the use of such sooty and higher sulphur coal can be overcome.
By using hydrogen in a fuel cell to produce electricity to power an electric motor. A fuel cell is an electrochemical device that produces electricity efficiently, silently and without combustion. Hydrogen fuel (which can be obtained from methanol, natural gas, water, or petroleum products) is combined with oxygen (from air) to produce electrical energy. Fuel cells and batteries are similar as they both deliver electrical power from a chemical reaction. However, in a battery, the chemical reactants are stored within the battery, are used up during the reaction, and the battery must be recharged or thrown away. In a fuel cell, the reactants are stored externally to the fuel cell, so it will keep producing electricity as long as reactants (fuels) are delivered to the fuel cell. Therefore a fuel cell vehicle is refueled instead of recharged. A fuel cell engine is the complete set of components that integrate with the fuel cell so that the fuel cell’s electricity can power the vehicle’s wheels. Think of the fuel cell as the engine block in your automobile – in this case, it’s like a small electric power plant. As in the internal combustion engine, the fuel cell requires other systems to make it a complete energy source, including air, fuel and control systems. In a fuel cell vehicle, an electric drive system, which consists of a traction inverter, electric motor and transaxle, converts the electricity generated by the fuel cell system to traction or motive power to move a vehicle. Also, when using a fuel other than direct hydrogen (such as methanol, petrol or ethanol), an on-board fuel processor is required to extract hydrogen from the fuel.
This is very uncertain. The Hydrogen economy is an economy where hydrogen becomes a pivotal and key part of energy requirements and hence the economy. Most technologies when invented and launched frequently fail on their first attempt. However, when customers begin to use the technology – take-up rates can show exponential growth. This is sometimes stimulated by either a crisis, changing tax or environmental legislation, a strong marketing drive or a change in people’s values. Up until now, Hydrogen has not really been promoted by governments as a serious alternative to normal hydrocarbons. Instead, renewable sources of energy have been promoted. The reason for this might be that Hydrogen energy is more difficult for customers to understand and there are some misconceptions in the market place that have not helped. Frequently muted concerns are that Hydrogen stored in tanks is dangerous – however, the Hydrogen tank is no more dangerous than a petrol tank. Similar types of LPG tanks have been installed in automobiles in Europe for many years without significant issues. The other issue is that you still need to produce the Hydrogen in the first place – this would often be through burning of hydrocarbons. However, solar can produce Hydrogen – so essentially the whole process could be clean – albeit costs and complexity are currently high. The other issue is that gasoline stations would need to be converted to supply hydrogen to automobiles. This is a significant capital investment issue – and until there is sufficient demand, the economics are not good. It’s the “chicken and the egg” syndrome – without one, you wont get the other - but until there is good coverage, most people will not feel like buying a hydrogen automobile – since they will fear running out of fuel. The technology is likely to start in bus fleets in cities and spread in highly populated regional areas with the higher environmental restrictions and tax breaks – examples could be California (LA and SF) and Germany. If oil prices sky-rocket, the US government might decide that it becomes a strategic initiative to maintain security of energy supply. The fact that methanol can be extracted from corn and sugar cane means that a combination of highly intensive corn and sugar cane agriculture with solar power to produce Hydrogen – then the fueling of automobiles from fuel cells could be feasible if enough organization, tax breaks and proactive initiative was taken. The question is – can and should the developed world rely on the promise of sustained oil supplies from OPEC countries or should they diversify away from oil into renewables, coal, gas and hydrogen (supplemented by methanol from agriculture) and possible expansion in nuclear power?