Tech Talk - ten years is a long time to wait for power

Today the British Government are announcing the construction of the first new nuclear-powered electricity generating station in 20-years. The new plant, which will replace plants that will close will go up at Hinkley Point, and will be constructed by a French firm, with significant Chinese investment, and with a promised subsidy from the Government. It won’t, however, start producing electricity until 2023, and even then only if everything goes well.

Euan Mearns has been pointing out some of the problems that the country faces as it closes existing power stations in order to meet environmental directives from the EU. The long-term supply of power at an affordable price is being increasingly challenged as the margin between demand and available supply shrinks. The leader of the Labor Party is promising that prices will be fixed by edict, an action that is unlikely to encourage investment at a time when it is clearly needed to help provide additional plants to replace the lost capacity.

The information on the new power station construction highlights the problems that the county will increasingly face. Although it is relatively quick and straightforward to close a plant (and then to demolish it), funding, permitting and constructing a new plant will, in this case, take ten years. In the interim it will likely prove increasingly challenging to find an adequately priced source of power for the 7% of the British market that will be supplied from the new facility.

Power generation requires both that a power station exists to transform fuel into electricity, and also that there is a steady supply of that fuel (or energy source in the case of the renewable generators that rely on wind, the sun or water). The ten-year time frame for construction of the new plant means that it will not appear in the energy equation until there has been a considerable change in the available supplies of the different power sources needed to keep the electricity flowing. In the meanwhile it would appear that the UK will increasingly rely on diesel generators to provide more than just back-up power.

It is a time-scale that will see a continued decline in domestically produced oil and natural gas in the UK, and with domestically produced coal-fired power still viewed negatively, the country will be forced to increasingly rely on imports from the rest of the world to provide the fuel needed. But in that time frame the evidence that oil supply is finite is going to become much more visible to the general public. A steady growth in demand of around 1 mbd for oil cannot be sustained over the next ten years, since there are an inadequate number of new prospective fields capable of providing that increment, especially when the need to replace an annual decline of around 4.5 to 5 mbd in existing production is also factored into the equation. (Remember, in that time-frame, that current fields such as the Bakken and the off-shore Brazilian fields now coming on line will have moved well into post-peak production).

Oil-fired power, whether through use of major power plants, or through the more widespread use of diesel generators, will become an increasingly impractical part of the answer. The anticipated solution is expected to be through the more widespread use of natural gas.

The advent of large volumes of shale gas, and easier access to some of the large fields in Asia continues to radically change the potential supply sources and prices that will be charged for a fuel that can arrive either through pipeline or by LNG tanker. Yet, as the large conventional fields such as those in Turkmenistan are tapped to feed the growing Chinese market, the supply to the rest of the world will have to come from the more expensive shale gas and from regions more expensive to develop. Well costs are now quoted routinely at around the $10 million mark, and can only be anticipated to continue to rise. As the global market for natural gas at a higher price provides an incentive for increasing levels of exports from the United States, the current glut in supply will disappear and prices will to more closely follow those on the global market. This could well stop the migration of industry from the more energy-expensive parts of Europe to the USA, but it is unlikely that US prices will reach those of Europe, and so although overall prices will rise the relative ratio of prices will not change and that drift will likely continue.

But putting too much expectation on natural gas to become the energy savior of the world is unwise, given the very rapid decline in yield from existing wells, and the consequent need to continually drill new ones to sustain supply. Further the potential supply from some anticipated reserves has been reduced, as exploration shows that limits to both what is there and what can be reasonably recovered. (The Polish experience is a good example of this). This is likely to become increasingly clear over the next decade, as global natural gas reserves are asked to carry a significantly greater portion of global energy demand. Natural gas-fired power plants are cheaper and faster to produce than nuclear plants, and coal-fired plants can be converted to gas use. (The power plant at Missouri S&T, for example, although fired by coal and wood, was fitted with gas burners that were, for most of its operational life not used).

But there are limits to the practical volumes of natural gas that can be supplied, at reasonable cost. As these bounds start to appear over the next decade the questions that will arise will start to focus on what can be used to replace it. To date renewable sources have not provided the panacea that was heralded to occur as they were eased into the market place. The economic subsidies used to encourage more widespread use of solar and wind have become less acceptable to Governments and their budgets, and it seems unlikely that the subsidies can continue to be used to foster future growth at greater levels of scale.

Domestically produced coal-fired power will likely continue to be a major part of energy production in the less well-developed nations, simply because it will provide a viable way of providing power at an acceptable financial cost. Whether the vehement denunciations of its use in more advanced countries, as a source of greenhouse gases, is still dominant in ten years, particularly if global temperatures continue to remain relatively stable, is more a political rather than an energy source debate. But the decisions on what to build post-Hinkley Point will have to be made soon, and the choice may be more limited than is yet to be recognized.

My apologies, this is being posted from Terminal 5 at Heathrow, where I am frantically charging my laptop, as I travel through the UK. Posting will be a bit spotty for this week until I return home.

Biofuel in the air and expensive gas on the ground

There are a couple of items in the news today this week that mark the face of a changing world of energy supply. Of the two the increasing problems that the United Kingdom are facing with maintaining a viable energy program into the future is being marked with an escalating cost and the need for politicians to begin walking back from some of their previous statements. The other is the decision by Lufthansa to use a biofuel mix as a regular fuel for scheduled flights. The latter decision is a little more complex than it first appears, since the logistics of supplying the fuel mean that the aircraft (which will fly the Hamburg to Frankfort route) will only be fueled at one airport, and – to facilitate the monitoring of maintenance and other possible impacts – only a single plane will initially be involved in the trials., which will go on for six months. The testing can now begin since the standards for the fuel have now been approved by ASTM.

After blending with conventional jet fuel, new lubricity, distillation and composition requirements in D7566 must also be met. As a result, the blended jet fuel used in the airplane is essentially identical to conventional jet fuel and does not differ in performance or operability.

The biofuel will be supplied by Neste Oil, which has declared a target of 2 million tons (around 40,000 bd) of jet fuel by 2020. Given that this is a 50:50 fix of biofuel and kerosene to meet the above standard, lowers the volume of biofuel needed, with the source described as:

Produced by hydrotreating renewable raw materials, NExBTL aviation fuel is compatible with all aircraft engines currently in use. Production is based on Neste Oil's proprietary technology, which can make use of a flexible range of various types of vegetable oil and waste-based inputs, such as animal fat from the food industry. Neste Oil is committed to only using verifiably sustainable and fully traceable raw materials that can be tracked all the way back to the original source.

In the United States there have been single plane flight trials, with the “Green Hornet” (flight video ) using a mix that included camelina oil .

Turning from the good to the rather more worrying topic, the British gas industry is in the process of raising natural gas prices by some 18%, which also feeds through into the price that they charge for the electricity generated by the gas, and also supplied to customers. This is occurring at the same time as a report from a British car insurance firm has concluded that the increased price of gasoline (petrol) in the UK has driven some 1.3 million people (out of 31 million registered drivers) off the road, with the cost of car operation reaching $4,800 a year. This is an increase of over 20% in a year, and when taken with the rising price of natural gas is an illustration of the costs that are being incurred as the UK moves more strongly from an exporting to a fuel importing nation.

The U.K. Government is beginning to realize that, without a sufficient domestic resource, they are constrained to pay what the rest of the global community decides is a proper price for their fuel. The UK Government is putting forward a plan that will increase the emphasis on nuclear power and renewable sources of power. The problem is that, to comply with EU rules, the UK is going to have to close a quarter of its generating capacity this decade. The eight nuclear power stations that it is now anticipating private industry will build (though there is some doubt) won’t come on line until perhaps 2025.

Possible Nuclear Power Station locations in the UK (LSE )

In the interim the problems to the consumer of the rising price of natural gas is perhaps being reflected in the same way as it was for gasoline, namely a reduction in demand. In the first quarter of this year, while coal use rose (albeit with two-thirds of the supply imported) by 7%,, the demand for gas fell 20%. Renewable energy sources increased supply by 27% but this should be placed in the context that the overall contribution from renewables was only 3.3% in 2010. Demand has been met by coal

Power companies have been benefiting from local coal production, however, with the small but active number of British facilities recording a 31% increase in output in the first quarter. Deep-mined coal showed an 80% rise as stocks were depleted due to demand from the utilities.

The problem, unfortunately, remains that the coal-fired power stations are going to be pulled off-line soon, and so the cheaper coal-fired power will not be available, and (providing that there are power stations available) the reliance on natural gas will continue to drive prices higher, which is likely to be increasingly unpopular with the British public.

However the first large solar farms in the UK are now on line, although with a combined output of 2.4 MW they are not likely to have much impact on overall supply.

That lesson (of increasing prices costing politicians their popularity) has already been cited as one reason for the release of oil from the Strategic Oil Reserve in the United States. Unfortunately it would appear that this release, coming with the increase in demand that I have referred to earlier, has not had the hoped for impact on oil prices. And, equally unfortunately, that action is still some months before the elections of next year.

The British experience is beginning to show that demand can be curtailed by price, but that still requires that there be an adequate supply to meet such demand. The problems with finding reliable power sources by 2015 for the British electricity suppliers is beginning to become evident and will likely further influence political popularity there. But the UK does not have to hold a national election for some years. That is not the case in the United States, even though the prices of gasoline and natural gas are still well below that of Europe, but where the public is more sensitive to those numbers, and where the elections are a whole lot sooner.

OGPSS - At around 2 mbd - Nigeria, Angola, Libya and the UK oil production

The growing concerns about the stability of the countries of the Middle East and North Africa (MENA) because they make significant contributions to world oil supply adds additional meaning to these weekly posts on the world’s major oil producers. To briefly recap I looked at the top tier oil producers (as listed by the EIA (i.e. those who produce more than 3.1 mbd in 2008) in the first post of the series. (These were Russia, Saudi Arabia, the United States, Iran, China and Canada. ) In the second I looked at the next four countries on the list, namely Mexico, the United Arab Emirates (UAE) Kuwait and referred to Venezuela – subject of a series of posts earlier in the year. The third post covered Norway, Brazil, Iraq, and Algeria. And so now we move on to look at Nigeria (2.35 mbd), Angola (2.0 mbd) Libya (1.87 mbd) and the United Kingdom (1.58 mbd). The numbers in parentheses are the production numbers cited by the EIA for 2008. To further put these countries in context, these take us down to number 18 on the list, and with one more post I will have covered all the countries that produced more than 1 mbd on average in 2008.

I will start with Nigeria, which now is cited as producing 2.4 mbd of crude and condensate in January 2011. The country has been having considerable trouble with sabotage and internal unrest, which has had a negative impact on production. However the country signed an Amnesty Program with militants in 2009 which has reduced disruption. As a result in February Nigeria was able to raise production to 2.6 mbd. If this can be sustained it will bring production back over the peak level that was achieved back in 2005.


Note that, for crude oil production alone, Nigeria is listed as producing 2.17 mbd in January, according to the February OPEC MOMR. (Which is also a gain from the above chart). In light of some of my recent comments on who might be hurt if oil production in some of the MENA countries drops off, it is perhaps interesting to note which countries got oil from Nigeria in 2009.

Nigerian oil customers in 2009 (Source EIA )

Historically Nigeria flared much of the gas that was associated with the oil, particularly in the Niger River Delta, where much of the oil is found. That practice led to some of the more dramatic stories that came from the region, before the amnesty. There is, however, a concerted effort now to capture and market this natural gas, as well as that which comes from gas wells in the country. This has led to some optimism by the Government over future sources of revenue.

The Minister also disclosed that the establishment of two new Liquefied Natural Gas, LNG plants, in Olokola in Ogun/Ondo States and Brass LNG in Bayelsa state, will create over 7,000 jobs and inject over $1billion into the host communities.

There are a total of 6 LNG trains at Finima, on Bonny Island, first coming into production in September 1999, and supplying a variety of customers. While the capacity is at 1.1 Tcf, recent figures have been at about half that volume. (And this is about the same volume that continues to be flared in the country.)

With Nigeria having increased overall production since 2008, though potentially having limited potential for much greater increase, the next country down the list is Angola which, since 2007, is also in OPEC, and OPEC list the January Angolan production of crude at 1.62 mbd. This is significantly below the overall 3.8 mbdoe that BP has reported for total energy production in 2010. Because of some technical problems with water injection, being used to help move oil from the reservoirs, moves to address the problem might overall, reduce the average for 2011 to 3.4 mbdoe. Angola exports about 1. 7 mbd of oil, but is responsive to OPEC requests to control production in order to keep prices at the OPEC comfort level. (Which has risen from around $75 to over $100/bbl in the last few months). Thus the declines shown in the EIA plot below, which only shows through 2009, are more politically induced than due to geological conditions. The EIA, for example, lists project for this year alone that are expected to add 650 kbd to production, and likely export. Unfortunately we are now far enough down the list that while these numbers are significant in their own right, and for the country they may not give that much help to the overall shortages that may evolve over the next year.


Angola currently is building an LNG project at Soyo, expected on stream in 2012 which will handle around 1 bcf/day. Apart from the LNG, which will be exported, the plant will send some 125 mcf/day of natural gas into a distribution network for domestic consumption. Until the plant comes on line most of the almost 1 bcf of natural gas that is produced every day is either flared or reinjected to help with oil production.

Trying to project Libyan future production is rapidly becoming meaningless, I fear as the initial moves to remove the current Leader have not met with sufficient success to eliminate the possibility of civil war. It was only a few weeks ago that Libya was producing at around 1.6 mbd of oil, and Luis de Sousa has reposted an earlier review of the past history of their production. He presciently notes in that post that the rising population of the country is going to demand more of the resource be spent at home. The topic of Libyan production will likely continue to appear in other posts – as it just has – but at the moment it appears, for a variety of reasons, that the system is effectively shut down.

Little if any oil can be shipped out of Libya because most ports were closed. Meanwhile, storage tanks were filling up rapidly. Oil traders said one major oil company cargo ship was supposed to berth this week, but no one was at the port to deliver an oil shipment, and shipping companies were reluctant to send ships into the Libyan ports.

I have also discussed elsewhere the likelihood of sufficient increase in production in other countries to make up the shortfall. Gazprom has been helping Italy, for example, and Saudi Arabia increasing production, but how long this will last, and how much will ultimately be needed remains an unknown. It really depends on how many dominoes fall, and how long they remain on the table.

Which brings us to the United Kingdom. Back in the troubled days of the first oil shocks some thirty to forty years ago, it was the combination of new production from the fields in the North Sea and the North Slope that helped bring oil prices down to the low level which allowed the years of growth until now. But we have reached a point where those resources are beginning to disappear, and the UK has turned from an energy exporter to a growing importer. Euan Mearns has documented this progression in a much more detailed and better way than I illuminating, for example, back in 2008, the coming seriousness of their problem.

Euan’s plot of the UK Predicament, from 2008

If we look at the situation today, the reports for last year note

In 2010, the UK produced 850 million barrels of oil and gas equivalent (boe) or 2.3 million boe per day. Current plans now target reserves of 11.6 billion boe, 1.3 billion boe more than was anticipated a year ago, reflecting the outcome of increased exploration and appraisal activity across the UKCS and particularly West of Shetland. Oil & Gas UK believes there could be up to 24 billion barrels of oil and gas still to recover from the UKCS.

This was about 60% of the UK energy need. Production of crude for last November was 1.047 mbd from offshore, and 9,344 bbl from land wells. The natural gas numbers were 2.7 Bcf from offshore oil wells (as associated gas) and 2.8 Bcf from offshore gas wells. In addition there was some 12 kbd of condensate from the offshore gas fields.

Whether one uses Euan’s plot, or that from the Energy Export Databrowser:

UK Oil statistics (Energy Export Databrowser)

The UK is clearly entering a more expensive future as it must find more oil from overseas, just as that supply is tightening.

On the other hand, while the situation is getting somewhat worse more rapidly with natural gas, as the EIA plot below shows ( and it contributes to Euan’s total figures) there is a sufficient glut on the world market at the moment that there will not be that immediate a problem in the short-term.

United Kingdom trends in gas statistics (EIA )

UPDATE The energy situation in the UK is becoming recognizably more dire, and the Secretary of Climate and Energy, Chris Huhne has just pointed out that the price of $100 a barrel for oil justifies a greater investment in green technology

Drawing on research conducted for the previous government by Lord Stern, Huhne argued that a $100 a barrel price is the exact point at which the economics of climate change pivot so that it becomes cheaper for British consumers and businesses to invest in green technology than remain with the status quo.

He said that if oil only reaches $108 a barrel by 2020 as predicted by the US Department of Energy, which would also lead to higher gas prices, then "the UK consumer will win hands down". He said the UK consumer would be "paying less through low-carbon policies than they would pay for fossil fuel policies".

This does not recognize that most renewable energy technology currently focuses on generating electricity, while the crisis is in liquid fuels for transportation, and it also ignores the likely over supply of natural gas which is separate that price from the rising price of oil over the coming years. Tsk!

The current situation in the MENA countries is in such a state of flux, and the impacts barely recognized as yet, that it is becoming even more difficult to have any confidence that the predictions of performance that were being used only a couple of months ago will continue to have much validity in predicting what is likely to occur even in the relatively short term future.

The UK winter starts - salt, coal, and natural gas supplies

The severe weather that is sweeping the United Kingdom is posing an early demand on the stored supplies of fuel, and on the grit supplies that are used to de-ice travel ways. Part of the problem causing train delays is that the snow and ice are blocking the connections needed to transfer electric power from the rails to the train engines. At the moment it appears that up to 500 gas stations mainly rural stations in north-east England and eastern Scotland may run out of fuel over the weekend. Not that driving is that easy at the moment. When bad weather hit the UK last winter, the shortage of grit (which is largely salt) was one of the difficulties encountered by local councils. The government formed a “Salt Cell” to provide information on salt supplies and needs since salt comes from only three mines, one at Boulby in Yorkshire, the Winsford mine in Cheshire and the Kilroot mine in Ireland. The Winsford mine, which provides 50% of the UK salt need, can lift 500 tons an hour from the underground deposit and has been working 7-day weeks since last December.

With some councils reporting that 20-30% of their winter stocks have already been consumed, the Cell may need to be reactivated this winter. Typically the country stockpiles around 275,000 tons of salt for the winter, however when the country is totally blanketed with snow, then it can use as much as 194,000 tons in a day. (UK DOT figures). After the hiatus last year the Senior Advisor to the Government for Highway Maintenance found that there were no easy answers, since the problem is bound up in limited mine production, limited local storage capacity, the reliance on local authority to deal with the problem, and a European shortage of salt. Yet at the beginning of this season 18% of the UK councils did not have enough salt to get them through the anticipated demand for the winter.

For those who think that this is purely a European problem, Park Forest in Illinois is already noting that it has almost depleted its supply, and there is a state shortage of salt already. Illinois has an average salt bid of 1.4 million tons and this year the prices was $61.60 a ton, down from the $100 of the 2008-2009 year. McHenry County, west of Chicago, orders around 60,000 tons a year. Of course individual cities have different circumstances, Avon Lake near Cleveland, Ohio, for example, has stockpiled more than enough for the year. But there are already shortages showing up in other parts of Ohio that are driving prices back up, with prices of $142 a ton being reported. Pre-planning apparently works.

The problems with UK fuel supplies changes with the fuel that is needed. Coal, for example, is largely maintained in stockpiles at the power stations. In September (the last month with data available) there was some 17.6 million tons in those piles set against a September consumption of 3.63 million tons. (It might be noted that this was roughly half-a-million tons more than the 3.11 million turns consumed in September 2009). With the UK now importing roughly two-thirds of its need, having that stockpile, particularly in a hard winter, might be a wise precaution. About 80% of the UK power stations rely on fossil fuels, though there has been a move to using natural gas over the past few years. This is increasingly supplied by imports, with overall demand rising at 9.6% over the equivalent period in 2009 (). A third of the imported gas comes in the form of LNG, at a level of around 2 billion cf/day, and is needed as natural gas supplies from the North Sea are falling at around 10% per year.

Natural gas supplies in the UK suffer from the lack of sufficient storage capacity, and the limited size of the supply pipes from Europe. A recent plan to use a depleted field in the North Sea won’t come on line until 2015, if it is implemented.

Pipeline gas from Europe to the United Kingdom flows through the Interconnector with the terminal at Bacton and with flow to and from Belgium. During September and October the pipeline recorded record flows going to the continent (16,000 GWh worth), however with the onset of the cold spell the flow reversed.

Flow of gas in MWh equivalents from Belgium to the UK through the Interconnector pipeline (the dates are the end of November and December 1 )

And at 6 am on Wednesday the flow stopped (h/t Luis) however supplies increased through the Langeled pipeline connecting to Norway. And while there were some problems with flow from the gas being stored in the depleted offshore gas field at Rough, it is reported that five LNG tankers are on their way to the UK at the moment.

It is worth noting, in passing, that with five nuclear power stations on maintenance, the French have been importing electric power from the UK.

Power demand in France, where one third of domestic users rely on electricity for heating, is expected to reach a new record high at peak hour on Thursday, according to grid operator RTE.
With demand also at record highs on Wednesday, France was importing power from Britain at the interconnector's full 2,000-MW capacity until around 1630 GMT, National Grid data showed.

And, also in passing it is worth noting that the claims of increased deaths from global warming are not being borne out by the statistics in the UK. A study, back in 2008, noted that there had been no increases in summer deaths from rising temperatures, but rather a fall in winter deaths by some 3% in the UK. However the return of harsher winters has already had an effect. Local councils have reported that with the colder weather last year deaths increased by some 25,000 and one may anticipate a similar impact this year. In a normal year the cold-related winter deaths would average about 20,000.

Wind Energy Makes Progress, but will it be enough?

Over the last few days there have been several stories of wind energy, none in themselves remarkable, but which, put together show the progress that the technology is making. Consider, for example, the small community of Tocco Da Casauria in Central Italy. It is a small town of around 2,700 inhabitants that, because of its remote, mountainous location, has had to face expensive power costs in the past (about 3-times that of the average US household). However it has recently installed four wind turbines, and now not only has enough power for the community, but also exports a sufficient amount that last year it earned about $200,000, enough to significantly help with municipal expenses. (Though the turbines are privately owned the town gets a lease on the land, and a percentage profit from the power sale). Similarly, but on a smaller scale, the town has a solar array that lights the cemetery, raising about $2,000 which helps pay for the upkeep of the place. There have been six turbines in the farm which is one of 249 sites in Italy for which data is easily available, the first two turbines (which generated around 400 kW) were not successful, but the new set averages 2,500 operating hours/year and produces 3.6 MW.

However wind is not yet a major player in the Italian energy mix, and though Italy has a target of 17% renewable energy by 2020, it is still only at 7%, and is not reaching target goals. On the other hand, at the other corner of the European Union, consider the case of Scotland. Although the target is now to have 80% of that nation’s power come from renewable sources by 2020, recent successes have led the First Minister there to predict that 100% of the national power will come from renewable sources by 2025. The target of 80% by 2020 has only just been announced (last week) , up from the previous 50%, based in part on the perceived ability to reach an interim target of 31% by next year. Much of the increase will come from offshore wind farms, though the onshore Whitelee farm (which is expanding) already produces enough electricity to power Glasgow. Another onshore farm is planned for Shetland, but following protests from the local community, Viking Energy has just announced that the farm will be reduced by 23 turbines from the original 150. In addition the farm cannot be justified without a cable to carry the power to the mainland. Permission for that cable has not yet been given. Part of the problem has been the impact of the turbine installation on the deep peat bogs on the islands.

The level of local resistance to the farms, and its potential impact on overall rates for installation of the farms, and thus their contribution to future energy supply may have been underestimated in government. Which could be embarrassing in the future, since the provision of affordable, and sustained power is considered one of their responsibilities.

Whether the potential problems in Scotland presage similar problems for the overall power mix for the entire United Kingdom is similarly a question. The UK has just seen the opening of the Thanet Wind Farm, in the estuary of the River Thames.

London, September 29, 2010 — Vattenfall officially opened the Thanet Offshore Wind Farm, off England’s southeast coast. The wind farm has 100 turbines and will generate electricity equivalent to the annual consumption of over 200,000 British households.

The construction of the 300 MW Thanet Offshore Wind Farm has taken just over two years and the wind farm is expected to operate for at least 25 years. Between 2009 and 2011, Vattenfall plans to double its wind power electricity generation, constructing nine wind farms in six countries to supply electricity equivalent to the demand of 800,000 households annually.

Thanet is so far the company’s largest offshore wind farm . .

This moves the UK into the lead in regard to power from offshore wind farms. The islands have sufficient wind potential that it could provide a greater slice of the energy supply in the future.

The Offshore Valuation Group, made up of government and industry organizations, estimates if Britain were to develop just 29 percent of its potential offshore resource, this could deliver 169 gigawatts of capacity by 2050 and turn Britain into a net exporter of electricity.

This would involve installing 7.2 GW a year -- roughly equivalent to 1,000 7.5 Megawatt turbines -- with fixed offshore wind accounting for 5.4 GW of the average annual build rate needed.

The supply chain needed for this would have annual revenues of 62 billion pounds in 2050 and employ around 145,000 people directly, according to the Offshore Valuation report.

The other side of the story, however, comes from the costs involved. With the increase in the price of steel, and maintenance costs going up current projections may also be low.

However the UKERC have calculated that the cost per unit of energy – known as a Megawatt hour – over the 25 year lifespan of the farm is expected to be £149. That compares with £80 for coal and gas, and £97 for nuclear power.

(An) Onshore wind farm – at £88 per megawatt hour – is almost as efficient of fossil fuels but is hampered by complaints they ruin the landscape.

Current government plans are to have as many as 6,000 turbines located onshore, and some 4,000 offshore. However, as the scale of operations grow, so it can be anticipated that the size of the opposition may also increase. This has been, for example, the case in the United States where Senators such as Kennedy on the East Coast, and Feinstein on the West have objected to farm installations. Though the Cape Wind project is now approved. As sites move closer to construction it may be that more of this opposition may arise.

There is also, as the Scottish experience is indicating, the need to install the power cables that will carry the power from where it is generated, to where it is needed. And those cables themselves are sometimes controversial. It seems much easier to install the smaller systems, for local use, as in Italy, where the benefits are more visible.

Coal, carbon capture and cheap natural gas

There are a couple of interesting articles that came out today on the future of coal as a power source that indicate some of the shorter and longer term concerns over energy supply. One is a tale of the United States the other the United Kingdom.

Looking at the United States condition first, those that are concerned about the future climate of the planet are particularly concerned about the amount of carbon dioxide that is generated when coal is used to generate electricity. (I am not going to go through the pro’s and con’s of their arguments, I do that on Saturdays, and there are lots of others who provide stronger arguments than I). The world had been anticipating that the upcoming meeting in Copenhagen would lead to a new treaty, and set of international regulations to control carbon dioxide emissions. This would build on the Kyoto accords which are expiring. However it now appears that the chances of an agreement in Denmark is not going to happen, and with the chances of a climate bill passing the US Congress in the near future fading, an alternative path to emission control is perceived, by those concerned, to be needed.

Thus the EPA is taking steps to generate regulations that will enforce carbon capture and sequestration by those using coal-fired power stations to generate electricity. One of the problems with a large scale program to undertake this effort is that it relies on a set of technologies that are not necessarily all worked out yet.

Certainly carbon dioxide can be captured from flue gases, and then liquefied for transport to an site for injection underground. There have been demonstrations of this in the past, though it should be noted that the two sites that are often quoted as examples of the ability to inject carbon dioxide – Sleipner for example is reinjecting carbon dioxide that is a byproduct of the gas being produced at the site back into a saline aquifer some 1,000 m below the sea bed. The other success quoted is that where carbon dioxide is injected into an oil reservoir to increase tertiary oil recovery. And the success most often cited here is at Weyburn field in Canada.

The EOR technique that is attracting the most new market interest is carbon dioxide (CO2)-EOR. First tried in 1972 in Scurry County, Texas, CO2 injection has been used successfully throughout the Permian Basin of West Texas and eastern New Mexico, and is now being pursued to a limited extent in Kansas, Mississippi, Wyoming, Oklahoma, Colorado, Utah, Montana, Alaska, and Pennsylvania.

Until recently, most of the CO2 used for EOR has come from naturally-occurring reservoirs. But new technologies are being developed to produce CO2 from industrial applications such as natural gas processing, fertilizer, ethanol, and hydrogen plants in locations where naturally occurring reservoirs are not available. One demonstration at the Dakota Gasification Company's plant in Beulah, North Dakota is producing CO2 and delivering it by a new 204-mile pipeline to the Weyburn oil field in Saskatchewan, Canada. Encana, the field's operator, is injecting the CO2 to extend the field's productive life, hoping to add another 25 years and as much as 130 million barrels of oil that might otherwise have been abandoned.

The Weyburn site is also not using flue gas carbon dioxide. There have been considerable questions about the cost of actually doing the carbon capture and liquefaction, but for some it provides the only alternative to shutting down the coal-fired sector of electricity generation.

"CCS is the only climate change solution we have for the existing fleet of coal-powered power plants," said Sarah Forbes of the World Resources Institute.

Thus there is the new initiative being carried out by AEP at their Mountaineer power plant to capture the gas and reinject it underground. The trial is planned for a 12 to 18 month operation

This project will test Alstom's chilled ammonia technology for CO2 capture from flue gases particular to natural gas combined cycle (NGCC) power plants.

The test began in September and is a scale-up from an earlier test. However it is going to take some time, even after the project is completed, to collect analyze and evaluate the data that will result. Unfortunately I would suspect that the EPA is not going to wait, and the high energy and fuel costs that will be required for the sequestration and re-injection of the carbon dioxide underground will not be much of a factor in the agencies move to force the industry into that particular box.

This will produce a significant increase in the price of power at the plant, and since such plants need to make at least some money to continue operation, one might logically anticipate that this will drive up the price of electricity. (I have heard predictions that in Missouri – which gets some 85% of its electricity from coal – the basic cost of electric power at home may double). The impact, worldwide is also projected to be very expensive.

Earlier this month the International Energy Agency said the world will need to spend $56 billion by 2020 to build 100 such projects, with an additional $646 billion needed from 2021-30.

And so, as a result, one might anticipate that there would, where possible, be a switch to using natural gas, which produces less carbon dioxide, and which is currently in abundant supply over a much greater swath of the nation. That coverage was enhanced with the transition to full operation of the Rockies Express Pipeline which has just come on line and will deliver natural gas from Wyoming and Colorado, where there is a plentiful sufficiency, to the Ohio and points East which has been a bit short. Given the availability of shale gas and new LNG terminals to import gas from abroad, gas will likely remain cheap in the short term.

And it is that dilemma that is facing the power station operators in the UK. The abundance of natural gas supplies to the UK (a quarter of which comes as LNG) means that it may be cheaper to generate power with gas-fired stations that by using coal. But the EU is seeking to shut down the older, more polluting stations and has mandated that they only run for 20,000 hours before being shut down permanently in 2015. This has been why there has been a move to build new replacement stations such as that at Kingsnorth (recently postponed).

The problems that might then arise, as the gas supply, on which the alternative is currently focused, provides the lynchpin of the energy plans of most of the world, is that increased demand may shorten the effective economic life of that resource. Given that nations need to have some alternative source in their back pocket, the dismantling of coal-fired stations across Europe may mean that these resources won’t be available if needed, and the move to restrict new nuclear plants, may keep that from being an answer in the same way. We shall see!!

P25. Pick Points

Half-a-dozen or so stories of interest:

What to do about the contradiction that rising commuter traffic is moving to metro train and bus lines as a falling tax revenue reduces support to the systems, and they reduce service? There is not a lot of stimulus for renewables in the new package going through Washington. Much of the money is going for new transmission lines and $1 billion for a smart meter program. And the pressure mounts for more efficient cars.

Not to be outdone European leaders are writing letters to the President asking for climate change legislation, since without it, Europe is at a disadvantage. Although the UK may not be able to keep to the pace of the rest of Europe. Oh, and apropos the tidal system that was in Pick Points yesterday, there is an explanation of how it works. On the other hand they are putting $27 million into the next generation of biofuels, that includes a cellulosic ethanol project that relies on the gribble (I’m glad you asked - it is a marine woodlouse), as well as starting to build houses out of straw - no this is serious, but I do remember a certain rhyme . .

China will get six LNG plants. Given that they are projecting an increase of 16-18% in gas production, but that is from abroad. The success of the first coal liquefaction plant in Mongolia, it ran for 300 hours, is leading to plans for expansion. Chinese coal mine deaths dropped 15% last year. And they are planning to introduce more efficient and energy conscious vehicles. Even as China’s oil demand tanks.

In order to start providing gas for the proposed new gas line from the North Slope, Alaska has given permission for Exxon to start drilling at Point Thomson. Previously the State had cancelled the leases, but they have now temporarily been reinstated. At the same time the weakened economy is not seen as slowing the progress forward of the pipeline, though that is not what BP thinks.

The Iran-Pakistan-India pipeline continues to face problems relating to the price of gas to be paid . Meanwhile Iran’s objections to the pipeline under the Caspian (part of the Nabucco network) are seen as being objections to the loss of monopoly. Politicians from the countries that would receive the gas are urging support at their Budapest meeting. Bulgaria has signed an agreement with Azerbaijan to receive a billion cu m per year through the pipeline. However it is not clear whether Azerbaijan would merely act as a conduit, or whether it would supply the gas itself. And Turkey is thinking of holding the pipeline hostage to its treatment by the EU. Poland will be joining the Nabucco project. All this fuss about alternatives has led to some recriminations against Prime Minister Putin.

The turndown in the economy is hurting rig operations, and Baker Hughes will cut 1500 jobs. On the other hand Petrobras is hiring though reducing costs elsewhere to allow production efforts to continue.

And in the “Haven’t we been here before,” section I see that Libya is talking about nationalizing its oil industry.

For more stories see The Energy Bulletin or Drumbeat at The Oil Drum.

How do we make up for Mexico's declining exports?

The current turmoil over the supply of gas from Russia, highlights the increasing dependence that the world has to place on energy supplies from a shrinking pool of suppliers. This past week the Energy Information Agency (EIA) shows that the United States imported some 14.5 million barrels of oil a day (mbd). Domestically we produced 4.9 mbd, having fallen below 5 mbd just as the calendar kicked over into December, 2008. The October import figures the most recent available, (pdf) show 6 mbd came from OPEC countries and 7.4 mbd from non-OPEC nations.

This supply came from a total of 49 countries, ten of whom are in OPEC and 39 of whom aren’t. However if we count only countries that contributed more than 250,000 bd to this supply we end up with Canada (2,567 kbd); Saudi Arabia (1,487 kbd); Mexico (1,483 kbd); Venezuela (1,162 kbd); Nigeria (979 kbd); Iraq (577 kbd); Algeria (555 kbd); Angola (539 kbd); Russia (394 kbd); Brazil (354 kbd); the United Kingdom (386 kbd): and the U.S. Virgin Islands (267 kbd).

One of the reasons for putting the list up here and now is that we can come back, next year and see how things have changed, and note how and where the dependence has moved to. But, as I noted in Pick Points, Mexican production has fallen to around 3 mbd, of which half is exported to the U.S., and if their production continues to fall at 500,000 bd per year, then within this next year there is going to be some greater crunch between domestic use and exports. So where will the United States make up the difference?


Now the volume each supplies varies by month, two months ago Norway supplied (for that month) 2.175 mbd so that drawing conclusions from a single month is of no great value, but if one goes back and looks at figures for 2007 (pdf), one ends up with almost the same list, only Brazil having since joined (by 154 kbd). In 2005 the top 14 countries importing to the US would have dropped off Russia, Brazil and the U.S. Virgin Islands, but Colombia, Ecuador, Kuwait and Equatorial Guinea were still on it.

The largest proportion of the U.S. imports come from Canada, yet outside of the Oil Sands of Alberta and the possibilities of production from the Bakken shale, their production has been declining, with the Newfoundland fields perhaps peaking at 369 kbd in 2007. The oil sand production, currently at 1.4 mbd is scheduled to increase, with an initial target of 3.5 mbd, once planned for 2015, but now slipped back to 2020. Unfortunately for US consumers, there are two snags to relying on this source to offset Mexican declines. The first is the slowing of the expansion plans of those working the oil sands as prices fall; the second is:

The 2007 federal energy bill says U.S. government fleets can't buy fuel from the oil sands and other sources whose production emits more greenhouse gases than conventional oil.

And if someone gets serious about enforcing that . . . . .
So if Canada cannot expand their production enough, and Mexico is going to cut their exports, for the sake of discussion by 0.5 mbd, where do we look to next?

That would be Saudi Arabia, from which we get about 1.5 mbd. But Saudi Arabia is a strong advocate of OPEC production cuts and has already dropped their production from a peak of 9.7 mbd to 8.5 mbd in November. While it may go lower, probably not below 8 mbd, they have just warned Asian customers that cuts, of up to 15% will continue. So no luck there.

Moving down the list of suppliers, in terms of import size, that takes us to Venezuela. This is an interesting case, since there is a fairly large difference between how much oil the country says it is producing (3 mbd) and the amount others have estimated (2.4 mbd). In accord with OPEC wishes to cut production, so that prices will move back up, Venezuela is cutting some 189 kbd or production, 166 kbd of which was going to the United States. So I guess we’d better not look there.

Next on the list, moving down, is Nigeria, where we get just under 1 mbd. Well they are currently exporting, in total, around 1.66 mbd, but this is a cut of 12% (from 1.88 mbd) to accord with OPEC requests.. Although the country has a potential to produce perhaps 2.5 mbd, the problems that have been created by widespread conflict has pulled it down to perhaps the current level, although, with perhaps as much as 200,000 being siphoned off to illicit sales, it is going to be difficult to estimate true production – but I wouldn’t gamble on getting more out either.

And so we come to Iraq, which has now, with 0.577 mbd, made it to sixth on the list. A year ago I would have thought that increasing that number would have been almost impossible, but the nation is moving ahead with plans to double oil production (from around 2.5 mbd today, of which 1.85 mbd is exported), within three or four years. If this can be achieved, and one of the fields planned for expansion lies beneath Baghdad, then this could solve the US shortage , if not . .

The next candidate on the list is Algeria. But while their production is continuing to rise, together with exports, they also hosted the latest OPEC meeting with its call for 3.3 mbd of oil cuts. Thus while the US may get up to about a third of their exports, of about 2 mbd total production, their share is not going to go up in the short term, even though they hope, when markets grow, to increase production to 2.6 mbd by 2018..

Angola is eighth, but as a member of OPEC they are falling in line to drop production, from the 1.9 mbd that they produced in 2008, even though new fields are coming into production, and the production cut is anticipated to lower this to 1.5 mbd.

At ninth in line, there is Russia. But while Russia now vies with Saudi Arabia to be the worlds largest producer of oil, it has announced that it will go along with the OPEC cuts and, in collaboration with Azerbaijan, reduce their output by 600,000 bd. There is also a question as to whether overall Russian production has not peaked, since production last year fell year-on-year (Y-o-Y) by 815 kbd, to 9.74 mbd, with exports falling 16% to 3.53 mbd. Guess we had better not look there.

And so we come to the tenth candidate – which is Brazil. Brazil reached energy in 2006, but though a lot of credit was given to sugar cane ethanol the reality is that it was achieved with increased production of oil, particularly from offshore. However the costs for developing those fields is above the current price of selling the oil from those fields. So maybe we should not send out tankers down there yet.

Hmm, well lets see where that leaves us, Can it be that we are left hoping for production increases from Iraq as our likely savior, should demand start to resurrect?


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