Tech Talk - China, Russia and East Siberian natural gas

The recent agreement between Russia and China for the sale of some 38 billion cu m of natural gas a year for 30 years, at a reported price of $400 billion ends a long-going negotiation between the two countries over the price of that supply. (Which works out at roughly $10 a thousand cubic feet, just over double current US prices). The price apparently includes some $25 billion to help with construction of the pipelines that will start feeding gas into the Chinese networks within four years. It is less than the price of LNG in the Pacific, and thus will likely lead to market adjustments for that product.

Figure 1. Potential interconnections to bring Russian gas into China (Washington Post )

It is equally of interest to see where the other ends of the potential pipelines lie, since this locates the natural gas fields that will be used to provide the supply. Looking at the distribution of pipelines and fields, the current preponderance of connections into Europe is hard to miss, at the same time as is the large gap in development in the Eastern side of the country.

Figure 2. Natural gas basins in Russia (Oil Peak )

Thus while the potential connection from Urumqi to Gorno-Altaisk allows the Chinese pipeline into a feed from the network that supplies Europe, that market is not going to go away. Yet the two towns are just 560 miles apart and the connection has been known as the Altai project, or Western connection, since it was first planned over 10 years ago, extending a new pipe up towards Yamal and the basins that feed Europe.

Figure 3. The Altai pipeline project (Gazprom )

Developments that reach up into Eastern Siberia, above Lake Baykal and Mongolia into the fields of Kovyktinskoe and Chayandinskoye through the “Power of Siberia” pipeline will allow gas from those fields to also feed Western China.

Figure 4. The connecting fields and pipelines for natural gas from Eastern Siberia (Gazprom )

The gas fields will feed into gas production facilities in Irkutsk and Yakutsk with oil production scheduled to start from Chayandinskoye this year, and natural gas production to follow by 2017. The field is expected to yield 25 billion cu m of natural gas and 1.5 million tons of oil a year at full production, and is estimated to hold 1.2 trillion cu m of natural gas. Kovyktinskoe was licensed to Gazprom in 2011 for exploration and production and is estimated to hold natural gas reserves of 1.5 trillion cu m. Smaller local fields at Bratsk and Chikanskoye have been developed since 2007, with the gas being used locally to supply the region.

Figure 5. Developing natural gas fields in Eastern Siberia (Gazprom )

These two fields alone therefore seem capable of meeting the current sales volume that is to be needed for China, given that the time to delivery is some four years, and both fields are anticipated to be on line, with the gas production facilities, within three years.

Pipeline construction is already underway. The “Power of Siberia” will initially connect into Vladivostock, taking the natural gas to the higher demand industrial Eastern China, but likely the additional funding that China is now providing will also help the Westward expansion to the Western gateway.

Figure 6. The Power of Siberia natural gas pipeline as planned. (Gazprom )

The natural gas pipeline is being routed along with the East Siberia – Pacific Ocean (ESPO) oil pipeline to simplify logistics, the second section of which was opened by President Putin at the end of 2012, a year ahead of schedule. The two sections will have a capacity of handling 80 million tons of oil a year (roughly 1.6 mbd) as supplies increase from the different fields to achieve that target. (The largest current contributor is the Vankor field producing slightly more than 500 kbd).

Yorubcheno-Tokhomskoye is expected to come on line in 2017, reaching full production of around 100 kbd by 2019, as the field develops the natural gas associated with the field will also be brought into the network.

There is anticipated to somewhere around 60 trillion cu. m of natural gas in Eastern Siberia (about 23% of the Russian reserve in 2009) and as this is only now being developed and the infrastructure put in place, it can be expected to last for some considerable time.

So far I have not mentioned the reserves that are now on line at Sakhalin Island. Gazprom built the Sakhalin–Khabarovsk–Vladivostok pipeline in 2011and this carries the natural gas down to Vladivostok, and thence largely into China and other Asian markets. The island also has an LNG facility which supplies that fuel to Japan and North Korea.

Figure 7. Natural gas pipeline from Sakhalin Island (Gazprom )

The pipeline is intended to carry up to 30 bcm per year of natural gas from Sakhalin fields, particularly those offshore.

Given the size of the fields that are thus available to Russia and that will feed into pipelines that will be in place at the time called for in the new agreement it is clear that the new market will not likely require any input from the fields that are currently supplying Europe and other markets.

As industries switch out of coal and into natural gas, however, a change driven partly by environmental and partly by cost considerations, so the demand for natural gas may potentially increase significantly. (As a minor indication of this the primary fossil fuel at the university in town is now natural gas and the coal fired plant just closed). There is less capacity to store natural gas than other fuels, which can raise some concerns over available supply in particularly cold days of the year. Such factors may change the situation somewhat, but realistically I would suspect that natural gas will play an increasing role in global fuel supplies for at least another decade.

OGPSS - Iran and the possibility of natural gas exports

There has been much talk in the current Presidential debates about possible changes in US Energy Policy, with Governor Romney suggesting that more Federal land be opened for prospecting for oil. Historically one of the regions included in such lists has been up in the National Petroleum Reserve in Alaska. And, perhaps anticipating the debate, the current Administration has already and recently moved toward opening those territories up for development.** However those fields have now been determined to be more natural gas than oil, and so hopes for finding more oil reserves has shifted into moves offshore, where Shell continues to be optimistic as it begins to sink new wells in the Chukchi sea – although well completions have now moved into next year. However it should be noted that there have been suggestions in the past that more of the hydrocarbons under the Arctic are gas deposits than oil, and this argument has been strengthened by the recent discovery in the Barents Sea of more gas, when oil had been anticipated.

The current large volumes of natural gas that are being developed and marketed, whether in the United States or from Turkmenistan, are making considerable changes in the economies of many countries. Russia, who lost the sales battle to supply natural gas to China now can no longer justify the expense of opening the Shtockman field, as alternate supplies are coming to the market at lower costs, and this will, in turn, cascade on to prices in Europe, where the advent of more gas in the UK is making it more difficult to justify a switch into a greater reliance on renewable sources such as wind and solar.

This entire scenario means that it is not necessarily a good time to have a huge reserve of natural gas, and to go to the market with this as a resource to generate income. This is particularly true, if the country in question is Iran.

Iranian Oil Minister Rostam Qasemi has announced that Iran’s exploitation of the South Pars gas field will equal Qatar’s exploitation of the gas field by the end of Iranian calendar year 1392 (ends March 20, 2014) if $54 billion is invested in gas projects.

Iran and Qatar share the largest natural gas field in the world, a reserve that is known as the North Field in Qatar, and as South Pars in Iran.

Figure 1, The South Pars field which lies between Qatar and Iran in the Persian Gulf (PetroPars Annual Report )

Qatar has been exporting Liquefied Natural Gas for a number of years, and has been well able to manage a steady growth in market penetration, as noted in a previous post, and this quote from two years ago:

Ras Laffan 3 Train 7 is the fourth 7.8 million tons per year LNG plant brought online by Qatar Petroleum and ExxonMobil joint ventures within the past 12 months. It matches the capacity of Ras Laffan 3 Train 6, one of the largest operating LNG production facilities in the world, inaugurated in October 2009. These mega facilities have sufficient scale to competitively reach markets around the globe. Qatar's giant North Field, which is estimated to contain in excess of 900 trillion cubic feet of natural gas, will supply both trains.

For Iran to anticipate that they can generate the infrastructure to compete with Qatar in the short term, given the time taken to invest, not only in the surface plant, but also in the tankers that become dedicated to the customers and the routes that must be followed, is more than naïve. That they can expect to do this at a time when, more than in any time in the recent past, there is an adequacy of supply unseen in a generation, suggests a message that can be meant for local consumption only.

But Iran has other problems. At present, as noted last time, natural gas supplies are barely keeping pace with an acceleration in the volumes required to meet internal demand. Any move to increase production will face competition not only from Russia (with available natural gas supplies once anticipated to be sold to the USA, and, when that fell through, then to China) and Qatar but also potentially from the United States itself, since as The OGJ recently noted

“U.S. LNG export potential is a major issue in Asia, particularly in Seoul and Tokyo,” said Mikkal E. Herberg, research director at the National Bureau of Asian Research (NBR)’s Energy Security Program and the report’s editor, “That’s especially true for the next 5 years until major Australian and other export projects come on line.”

With China getting more of its supply through pipelines this may also weaken the LNG market, even as Iran moves to step into these waters.

So can Iran also move its natural gas by pipeline, it is, after all connected by land to potential customers. Well, apart from the relatively obvious problems of trying to do this at a time when the nations concerned with Iranian nuclear policy are tightening their sanctions on Iran, as they are being seen to have more effect, the question comes back to who might be a potential customer. At present Turkey buys the bulk of Iranian natural gas exports but the European Union is expected to include natural gas in the list of banned exports at the meeting on October 15th. (Armenia and Azerbaijan buy the remainder of the current export volumes). There was a recent explosion in a gas pipeline carrying natural gas from Iran into Turkey, stopping the flow. But while that initially imposed a supply problem for Turkey, this has been met through increased purchases from Russia which currently has plenty. Thus it would appear that while Iran has more than sufficient supplies to move into an increased export position, the current political situation will likely preclude this happening in the short term, and the global over supply may well restrict Iranian penetration into that market in the longer term.

** September Alaskan pipeline flows were at 517 kbdm against the average for this year of 537 kbd, however as winter gets established the latest volume reported for 10/09/12 was 580 kbd, moving the pipeline away for the critical numbers.

OGPSS - Natural gas pipelines and regulation

In the last post on this topic I covered some of the earlier developments in the use of natural gas (NG) as a lighting source, and began to discuss its evolution into a widely used fuel. That use, and the international marketing of NG has largely come about as the increasing use of pipelines has made it easier to move NG from places where it is overly abundant, to those where it is not. A recent example of this has been the Rockies Express Pipeline (REX) which carries NG from Colorado to Ohio, and thence to points East. Out in the West NG is still abundant and so well head prices are low – in 2009 for example it averaged $3.21 per kcf in Colorado. That same year in Maine the residential price was $16.43 per kcf. (against $8.80 in Colorado). The well head price in Ohio fell from $7.88 per kcf, in 2008, the year before the pipeline was completed, to $4.36 in 2009.

The Rockies Express pipeline (Kinder Morgan )

As new fields, such as those in the various shale layers that are now becoming popular, are opened they only become significant as the gas that is produced from the well is connected into a distribution network. Pipeline costs have been estimated as around $1 to $1.5 million per mile. After the pipe is in place it is often hard to see where it runs, in the USA at least.

Pipeline route over the Marcellus Shale, after installation

In 2009 the US used some 22 trillion cubic feet of NG (Tcf) moving ahead of Russia to again become the world’s largest producer and consumer. In that year the greatest production came from five Western states.

Top Gas Producing States in 2009 (NEED )

The need for a network to supply other states, less fortunate in this resource, has largely been met, with new pipelines being installed as needed. However it should be noted that just having the production does not, in itself, create nirvana, since earlier this year New Mexico and the Southwest suffered from shortages since demand exceeded available supply due to an unexpected cold spell.

Natural gas pipeline network around the United States (EIA )

This network has made it much easier to ensure that gas is available to customers, when they need it. And while this has recently become more of an issue, as natural gas turbines are installed to provide back-up power to more intermittent power generators, such as wind and solar farms, NG fueled electric power stations have been the most, in fact almost the only, new power construction in the United States for several years.

As the experience in New Mexico showed, just having a network of pipes in place is not, in itself enough. The first need is that the gas must travel down the pipes to the customers at a given volume, and this requires that it be pumped under pressure. Rather than creating the driving pressure purely at the input end, the pipe travels through a series of compressor stations that raise the pressure along the pipeline length, as friction would otherwise reduce it to below viable levels. For safety reasons gas pressure is reduced as the pipes travel through urban areas, and the normal operating pressure can thus vary between 200 and 1,500 psi. For those that forget Boyle’s Law from high school science, at constant temperature, raising the pressure by a factor of 6 will cause an equivalent reduction in the volume of the gas that is being pumped.

However, if you consider the network as a schematic you will note a couple of additional features.

Flow Diagram of the US Gas Distribution Network (EIA )

The two additions are for temporary storage of gas for use at times when demand is high (Oops none in the Southwest - tsk !). The gas can be stored either as a gas, or it can be cooled to a liquid (which reduces the volume by a factor of 600 and stored in that form. The LNG facilities need a re-gasifier, and, if they are taking the gas from a pipeline, also a liquefaction unit to do the initial conversion. By using these facilities that are dotted around the country, pipelines don’t have to be as large to ensure that there is enough gas for the consumer at the high demand locations around the network.


Locations of storage facilities for natural gas including LNG import terminals (EIA )

I have used a map that shows the location of LNG import terminals, since this is an additional source of NG for the United States. Again the volume that is involved is a function of price, though often, to justify the cost of the parts of the supply train, there is a concurrent long-term commitment to a given price schedule, so that spot prices are not necessarily that valid, and what is paid in Japan, for example, is not indicative of prices elsewhere. That is particularly true at present since the loss in power from the nuclear reactors in Japan is expected to result in a long-term increase in LNG demand to replace the lost power.

Variation in the price of LNG in Japan (Mongabay )

As I write this the current quoted import price for LNG into the United States is $6.78 per kcf some $1.71 over the quoted Henry Hub price for NG.

One of the most powerful drivers in the growth of demand for natural gas has been as a result of its increased use in generating electricity. This is particularly evident as it takes market share from coal-fired power stations due to concerns over the emission of greenhouse gases.

Nationwide, coal-fired electric power generation declined 11.6 percent from 2008 to 2009, bringing coal's share of the electricity power output to 44.5 percent, the lowest level since 1978. Coal consumption at U.S. power plants paralleled the decline in generation, dropping 10.3 percent from 2008.

In sharp contrast, natural gas-fired generation increased 4.3 percent in 2009, despite the 4.1-percent decline in overall electric generation. The natural gas share of generation increased to 23.3 percent—the highest level since 1970. Electricity's share of the total U.S. natural gas consumption has also risen rapidly, growing from 17 percent in 1996 to over 30 percent in 2009

There is a greater capacity for gas-generated power than these numbers reflect, since the utilities still tend to use coal over NG for longer-term operation as the costs are lower.

The growth of this market developed after the Second World War, and the development of a distribution network. However in the years immediately after the war the industry was heavily regulated, both in terms of price and volume, in much the same way as the Texas Railroad Commission had regulated oil. But because the gas entered and left inter-state pipelines it was regulated under the Natural Gas Act of 1938 which among other things forbade the construction of a new interstate pipeline into a state that already had one. In 1954 the Supreme Court voted that the FPC should set wellhead prices for NG. This removed some of the incentive to develop new wells, and from then until 1968 production and prices remained relatively steady. In 1968 however reserves fell from 20 Tcf to 12 Tcf, and in 1969 they were down to 8 Tcf. With the industry still controlled, reserve additions failed to keep up with demand for the next 12 years. However the Arabian oil (and gas) embargo imposed in 1973 led the price of NG to multiply 750% between 1972 and 1976. Consumption fell at these higher prices, and the market re-equilibrated until 1980. But the over-regulation of the industry led to serious problems.

The interstate pipeline experience during this period was an unmitigated disaster. To deal with the shortages in the interstate market, interstate pipelines submitted curtailment plans to the FPC describing how they would determine who got gas and who did not. The plans gave top priority to residential consumers. Boiler fuel users, such as electric utilities, were given lowest priority. Users who experienced curtailed deliveries could either shut down their operations or switch to alternate fuels. During the winter heating season of 1977-1978, gas deliveries in New York and New Jersey were curtailed for everyone except residential consumers. Commercial users received only 94.3 percent of requirements, industrial users only 79.2 percent of requirements and electric utilities only 13.5 percent of requirements.

Just as the regulations were being changed to help resolve these problems, and de-regulate wellhead pricing, the Shah of Iran was overthrown, and prices took off again. This encouraged new drilling and in 1981 for the first time since 1968 more gas was discovered than was consumed that year. Unfortunately this happened just as the rise in prices was moving consumers out of the product. The result was a drop in demand, which bottomed out in 1986. With the increase in supply this generated a “gas bubble.” In 1986 the Texas Railroad Commission changed the rules to ease sales of the gas to end users rather than just the pipeline companies, at the same time the Federal Energy Regulatory Commission began the series of changes that, by 1992, meant that you no longer had to own a pipeline to be able to buy natural gas.

I’ll write about where that took us, and the evolution of the gas producers and market as I continue with this short topic next time.

Power shortages in India and Pakistan

The recent publication of the EIA review of Shale Gas has caught the world’s attention, and led to the perception that the coming decades may well see natural gas become the dominant fuel. It suffers, however, a couple of disadvantages that, for some countries, make it not always the fuel of choice. India and Pakistan, have serious energy shortages as Tom Whipple recently pointed out.

In Pakistan the electricity is now turned off for 18-20 hours some days in many cities and 20 hours in rural villages. The onset of summer temperatures, shortages of fuel oil for thermal generation and falling water levels have increased the power shortfall to record levels. Without electricity to run the pumps urban water supplies quickly shut down. Without power to run the mills, exports are falling, leaving the country without money to import oil. In short we are seeing a classical downward spiral.

At the same time, in India, the domestic natural gas supply is falling, requiring increased, and more expensive imports that can only be achieved using LNG resources.

There have been discussions for years over the possibility of running gas pipelines from Turkmenistan and Iran down through Pakistan and into India to provide the natural gas needed to help. The TAPI pipeline from Turkmenistan is currently at a stage where it may be moving forward. Pakistan is ready to commit to purchasing gas by this July, but . . .

.

In the four nations’ ministerial meeting last week, both India and Pakistan had agreed to the broader aspects of the gas sales and purchase agreement (GSPA), but crucial things like the price of gas and transit fee are yet to be decided.

At present the Turkmen are expected to demand at least $7 to $7.50 per kcf, which is the price that they are getting from China. And transit fees to get the gas through Afghanistan and Pakistan to India will be added to that. (In context that is about the same price as LNG when it is currently delivered in India, and above the $4.94 to $6.42 price of domestically produced gas).

The current hope is that the pipeline will be started in 2013, with full flow to all three countries by 2016. The pipeline will have to run a thousand miles before it reaches India. And this highlights one of the problems with natural gas. It is harder to deliver than other fuels.

Oil can be put on rail cars, or tankers, as well as being piped, as can coal (though there are very few places that use pipelines to move coal). But natural gas either requires a direct pipeline, or it has to be condensed to liquid form for shipment. When large volumes are involved turning the NG into LNG requires construction of both a condensing plant at the supply end and a re-gasification unit at the customer end. Both require time to build. And one the gas is regenerated, the customer has only a limited capacity for storage, and depends on the flow coming through the delivery pipe to keep power being generated.

Coal at the other extreme used (in my youth) to be delivered to our house from the back of a horse-drawn cart. It was dumped in the street, and we shoveled it into the “coal bin” out of which we then hauled it, a bucket load at a time, into the house, and dumped it on the fire. Logistics were a lot simpler, and we kept at least a couple of weeks supply in reserve in the bin.

Times have changed somewhat, for although shovels may still dig out the coal, they now can load a hundred tons, rather than a few pounds. Rail cars can haul 120 tons apiece in unit trains of 100 cars, and power stations may use 10,000 tons of coal a day to generate 850 MW of baseload power. But the coal is often still dumped in heaps at the power station, to be used when needed. Stations will usually keep 60 to 90 days of supply on hand.

India is aware of these advantages, but has internal problems with developing enough domestic coal supplies for the power that it needs. Coal India has said that it can only deliver 100 million tons against the 330 million ton increase in demand that, over the next five years, that power stations now being built will need.

With domestic coal production floundering amid a sharp upsurge in power capacity addition, over 40,000 MW of new generation capacity could get stranded over years for want of fuel. This is close to 70 per cent of the power capacity slated to come up during the period, most of which is being set up by private developers.

With a current generation capacity of 173,626 MW, this threatens the generation of some 42,000 MW.

There is a catch with using imported coal to meet all the shortfall, because of the construction of the Indian boilers. They blend about 10% of the higher thermal content imported coal with domestic coal but there are technical problems with a higher concentration that limit how high it can be raised, as well as the additional cost factor. However new construction can be built to handle higher concentrations of imported coal, it just costs more – which is expected to be a problem in relatively poor parts of the country.

Seeing this as an opportunity, however, Adani Enterprises, an Indian coal company, has just bought the Abbot Point coal terminal in Australia, after buying coal properties in Queensland last year. Over the next five years they will bring the mines on line and be able to feed up to 50 million tons into the Indian subcontinent. It is not enough, in itself, to meet the shortfall, but it is evidence that firms in India are aware of the problem and are moving to find answers. They will do so, however, in the face of stiff competition from China. And this competition underlines the conclusions that I drew in an earlier post about the unrealistic projections of future coal use by folk such as Tad Patzek and Dave Rutledge.

Unfortunately also this does not solve the immediate problem that India faces with a current shortage of available fuel. Nor does it get Pakistan any closer to finding a short-term solution to power shortages in that country. There comes a certain point where, when warnings go unheeded, the consequences must be suffered, though sadly often not by those who weren’t paying enough attention.

The Japanese fuel crisis

One consequence of the Japanese earthquake and tsunami that is not receiving as much press as the ongoing struggle to cool the damaged reactors, but which continues to influence more people is the lack of fuel. Nine of the Japanese refineries were damaged and put out of action, and this dropped the amount of fuel being refined from 4,500,000 bd down to 3,100,000 bd. (Note that the Guardian report I quoted earlier was off by a factor of ten.) The lack of fuel for transportation affects not only those in the disaster area, but also those away from it, since food and fuel itself depend on transport to move it to customers around the country.

"What we urgently need now is fuel, heavy and light oil, water and food. More than anything else, we need fuel because we can't do anything without it. We can't stay warm or work the water pumps," said Masao Hara, the mayor of Koriyama city, in Fukushima prefecture.

.
The refineries that remain in production are responding to the need. Idemitsi Kosan has raised production at its four refineries by 83,200 bd (from 87% to 100% production) and Cosmo Oil has raised production at its two operating refineries by an additional 80,000 bd but this does not match the size of the problem.

There are several different aspects to the problem, first the oil has to come ashore. With ports closed and unable to re-open for possibly months, shipments from the Middle East, which supplies 80% of Japan’s need, have now been curtailed until the situation becomes clearer. Within the country the Japanese Government has released around 8 million barrels of oil from their strategic reserve. It is also shipping 250,000 barrels of refined product to the area affected by sea (though this runs into the issue of how to get into the ports and distribution network). At Chiba some of the port has been able to re-open ) but not the terminal that fed to the Cosmo refinery (since that had burned).

Then the oil must be refined, there are 29 refineries in Japan, and Wikipedia lists them as follows. (I have modified the list to show which ones have had a status change).

▪ Chiba Refinery (Cosmo Oil) (Cosmo Oil), 240,000 bbl/d (38,000 m3/d) CLOSED BY EARTHQUAKE & BURNING
▪ Yokkaichi Refinery (Cosmo Oil), 175,000 bbl/d (27,800 m3/d) INCREASING PRODUCTION
▪ Sakai Refinery (Cosmo Oil) (Cosmo Oil), 80,000 bbl/d (13,000 m3/d)
▪ Sakaide Refinery (Cosmo Oil), 140,000 bbl/d (22,000 m3/d) INCREASING PRODCTION
▪ Muroran Refinery (Nippon Oil Corporation (NOC)), 180,000 bbl/d (29,000 m3/d)
▪ Sendai Refinery (Nippon Oil Corporation (NOC)), 145,000 bbl/d (23,100 m3/d) CLOSED BY EARTHQUAKE
▪ Negishi Yokahama Refinery (Nippon Oil Corporation (NOC)), 340,000 bbl/d (54,000 m3/d) CLOSED BY EARTHQUAKE
▪ Osaka Refinery (Nippon Oil Corporation (NOC)) 115,000 bpd
▪ Mizushima Refinery (Nippon Oil Corporation (NOC)), 250,000 bbl/d (40,000 m3/d)
▪ Marifu Refinery (Nippon Oil Corporation (NOC)) 127,000 bpd
▪ Toyama Refinery (Nihonkai Oil/Nippon Oil Corporation (NOC)), 60,000 bbl/d (9,500 m3/d)
▪ Kubiki Refinery (Teikoku Oil), 4,410 bbl/d (701 m3/d)
▪ Chiba Refinery (Kyokuto) (Kyokuto Petroleum/ExxonMobil), 175,000 bbl/d (27,800 m3/d) CLOSED BUT RESTARTED
▪ Kawasaki Refinery (TonenGeneral Sekiyu/ExxonMobil), 335,000 bbl/d (53,300 m3/d) CLOSED BUT GETTING READY TO RESTART
▪ Wakayama Refinery (TonenGeneral Sekiyu/ExxonMobil), 170,000 bbl/d (27,000 m3/d)
▪ Sakai Refinery (TonenGeneral) (TonenGeneral Sekiyu/ExxonMobil), 156,000 bbl/d (24,800 m3/d)
▪ Nishihara Refinery (Nansei sekiyu/Petrobras), 100,000 bbl/d (16,000 m3/d)
▪ Keihin Refinery (Toa Oil/Shell), 185,000 bbl/d (29,400 m3/d)
▪ Showa Yokkaichi Refinery (Showa Yokkaichi/Shell), 210,000 bbl/d (33,000 m3/d) SENDING PRODUCT OVERLAND
▪ Yamaguchi Refinery (Seibu Oil/Shell), 120,000 bbl/d (19,000 m3/d)
▪ Sodegaura Refinery (Fuji Oil Campany), 192,000 bbl/d (30,500 m3/d) INCREASING PRODUCTION
▪ Kashima Refinery (Kashima Oil Campany/Japan Energy), 210,000 bbl/d (33,000 m3/d)CLOSED BY EARTHQUAKE
▪ Mizushima Refinery (Japan Energy) (Japan Energy), 205,200 bbl/d (32,620 m3/d)
▪ Shikoku Refinery (Taiyo Oil), 120,000 bbl/d (19,000 m3/d)
▪ Ohita Refinery (Kyusyu Oil), 160,000 bbl/d (25,000 m3/d)
▪ Hokkaido Refinery (Idemitsu Kosan), 140,000 bbl/d (22,000 m3/d) INCREASING PRODUCTION
▪ Chiba Refinery (Idemitsu) (Idemitsu Kosan), 220,000 bbl/d (35,000 m3/d) CLOSED BY EARTHQUAKE BUT BACK ON LINE AND INCREASING PRODUCTION
▪ Aichi Refinery (Idemitsu Kosan), 160,000 bbl/d (25,000 m3/d) INCREASING PRODUCTION
Tokuyama Refinery (Idemitsu Kosan), 120,000 bbl/d (19,000 m3/d) INCREASING PRODUCTION

(The last four refinery increases in production will add another 83 kbd to the total.)

By the end of the month it is expected that the recovery will only be to 3.4 mbd although this will still leave the country some 1 mbd short of the refined fuel it needs.

At present only one LNG terminal, at Shinminato, remains closed, but it is unlikely that this will reopen in the near term. The rest are operational, and LNG cargoes will be made available from a number of sources, if needed.

Japanese LNG ports

The northeast coast ports of Hachinohe, Sendai, Ishinomaki and Onahama are so severely damaged that they are not expected to return to normal operations for months.

Looking at a map (from Stratfor showing the power plants, and the road layout, the damage to the distribution network with the destruction at Sendai illustrates the problem in gaining access to the damaged area and in sending in new fuel. Food to parts of Ishinomaki has had to be delivered by helicopter, and for a town of 160,000 this is not nearly enough.

As the Independent reports

On the drive north out of Sendai city in northeast Japan, a slip-road takes you to a motorway that would normally be filled with traffic but was this week a scene of destruction to rival the most far-fetched Hollywood disaster movie. A thick coating of mud had been deposited at the toll booth, along with smashed vehicles, motorbikes and heavy machinery from a nearby factory. Beyond the booth, the road rose up to meet the highway and a panoramic view of the blitzed landscape below, where a jumble of hundreds of cars, trucks and splintered debris stretched as far as the eye could see. In the background, thick black smoke billowed from fires burning at a damaged oil refinery near the city bay.

Japanese infrastructure (Stratfor)

There are trunk pipelines running from the main LNG terminals, to assist in distribution.

Japanese trunk pipelines and LNG terminals

Fuel needs are not just for gasoline and diesel for vehicles. With the bitter cold that remains over much of the north of Japan, and no electric power, kerosene is also needed for heating. For domestic heating many homes rely on kerosene stoves to heat individual rooms in use, rather than using central heating. Stocks had been falling, before the earthquake, due to the severe winter this year. And with stocks being sent to help refugees, there are now shortages in other parts of Japan.

While there are some indications that the nuclear problems may be being brought under control, the problems of fuel shortage and the cascading problem of food, fuel and other resource distribution that it brings with it, are likely to remain in Japan for several weeks, as the crisis continues.

Japan - using water cannons and replacing lost power

There are two different time intervals (short and intermediate term) for my comments today on the problems that Japan now faces with their nuclear power stations, following the earthquake and tsunami that have left the nation facing concerns over radiation and a shortage of power, that have accompanied the vast and tragic damage to people and property. I am gong to give a short technical comment on putting water on the nuclear station fires (wet stuff on red stuff as they say in the trade) and then comment a little on what the alternatives might be for replacing the lost power in Japan. (UPDATE: The loss of petroleum products due to the damage to nine refineries has cut the amount of oil and its products that is available from 450 kbd to 310 kbd. )

The first aspect of the problem relates to the immediate short-term, and the need to cool the reactor sites and the spent fuel pools at the Fukushima Daiichi power plant. Because the attempt to drop water onto the critical areas using helicopters did not work, the current plan is to use police water cannon. Police cannon, for those who have lived a righteous life, are used to control riots where it is desirable to minimize damage to the participants. They can be used either with plain water, or a small amount of a polymer (also used in fracking operations) which reduces friction (it is usually a poly-acrylamide). The latter is sometimes referred to as “Banana Water” since when it is used it makes the ground surface very slippery. After all, it is hard to continue a riot when you cannot get up off all-fours. (The polymer also makes the jet throw considerably further). A water cannon might throw a jet up to 60-meters at a working pressure of around 160 to 200 psi. They are generally designed for relatively close operational ranges, and with a stream that disperses. More effective designs to throw longer distances would have a greater section of straight section behind the nozzle (to stabilize flow) though sometimes internal flow straightening devices are used instead, allowing a shorter barrel.

However, should they wish to get more water into the area from further away, they might want to consider using some of the old hydraulic pumps and monitors left over from the recent past when coal was mined hydraulically in the Hokkaido (large pdf). These can deliver over a thousand gallons of water a minute, with sufficient power that they can mine coal from more than a hundred feet away. The reactors are slowly cooling, and it is hoped, once the water is available to accelerate the process, that those particular problems will subside.

In the intermediate term there is the loss of power from the eleven reactors that have been taken offline. Japan suffers from a lack of indigenous fuels. though it has sought to improve the efficiency of consumption, and thus lowered demand over the past decade the demand for oil and natural gas has remained high. The demand may be constrained in the short term by the disaster, since roads and infrastructure have been severely damaged, with road displacements of over a foot in places. But demands for some form of power, and the need to get the country re-mobilized may shorten any significant decline in demand. Moreover use of fuel oil has, recently, been rising reaching 151,000 bbl/day in January.

(Source EIA)

Twenty-four percent of Japanese electricity is produced from nuclear power and it is a portion of this that may now be out of commission for years.

The Japanese are reported to have shut down some 6,800 megawatts of power, and it has been calculated that, were this to be totally replaced by oil, that this would impose an additional demand of 238,000 bd on the market. On the other hand were it could be replaced by natural gas, a perhaps cheaper alternative, then demand would increase by perhaps 1 billion cu ft/day (BCF/d).

There are several ways in which the power can be replaced, but they will likely be focused on the use of fossil fuels. It should not be forgotten that five coal-fired power stations were shut down by the quake and tsunami, and cargoes for those stations are now being picked up by other stations in Japan.

According to market sources, the five affected power plants are the Tepco and Tohoku Electric joint venture 2,000-MW Soma Kyodo plant; Tohoku Electric's 2,000-MW Haramanchi plant; Joban's 1,600-MM Nakoso plant, and Tepco's 600-MW Hirono and 1,000-MW Hitachinaka plants.

Analysts said the equivalent of 10% of Japan's installed coal-fired generation capacity for electricity was currently offline.

The coal-fired plants will likely prove faster and simpler to repair and bring on line than the nuclear plants.

(Source EIA)

Until the recent events occurred, it was anticipated that the large use of coal in the country would fall, and be replaced by nuclear power. That trend is likely over, and the coal markets are already anticipating the switch back. As noted on Seeking Alpha, the question that arises, in part, is just where it will come from.

No matter the outcome of the current problems with the three old-style reactors in Japan, all of which need pumps to be secure from damage so water can be pumped up into the reactor core to cool the fuel rods (vs. the newer designs that use gravity to let water fall down onto them), one thing is certain: Other coal-fired plants in Japan will be working overtime to make up for this loss of power in order for re-building to be able to take place.

One additional reminder: It isn't as if China isn't already desperate for US and Canadian coal. It isn't as if Australia hasn't already had to reduce coal production as a result of the flooding there. It isn't as if India doesn't need more of both types of coal to power and build infrastructure there.

Utilities in Japan were already taxed, before the earthquake, given that January was the coldest in 25 years.

The 10 main utilities consumed 5.21 million tonnes of thermal coal last month, up from 4.55 million tonnes a year ago. They burned 698,385 kl of direct-burn crude oil (Ed. Equivalent to 141 kbd), rising from 440,534 kl a year ago. LNG burn also climbed to 4.12 million tonnes from 3.71 million tonnes.

With the cold weather diminishing (although it snowed around the damaged reactors yesterday) fuel demand would normally decline, but the balance between what supply is available and that which can be delivered is, in places now as much as a 25% shortfall. This has meant rolling blackouts that may well last into April. Some of this can be alleviated by load shedding by customers, and a re-distribution of load through scheduling. That will, however, take some time to organize,

Repair of the nuclear power stations is going to take a long time, and some may not be replaced by the current means of generating the power. It is perhaps likely that the emphasis will switch to natural gas, since there are spare turbines available, and a plentiful supply of the fuel. Since Japan would be importing LNG this has already given rise to an increase in price.

South Korea said on Sunday it will supply LNG to Japan's utilities after Tokyo made a request on Saturday. It added that Japan was likely to import an additional one million to 1.5 million tonnes of LNG per month after April.

However Korea, which also buys in that market is not as concerned with the rise in gas prices longer term, instead it worries about the rising price of coal, if this is used to replace the lost nuclear power. Coal is a likely intermediate-term answer that Japan may have little alternative but to adopt. But it will depend on who can get the most power available the fastest that may ultimately decide how the Japanese energy picture now changes.

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 BP Energy Outlook to 2030 - a review

There is a significant reliance, among those who write on fossil fuels, on the statistics that BP annually compile on global energy production. For example it provides underlying information for Energy Export Databrowser, as well as many of the posts at The Oil Drum. And so when BP just released their forecast for Energy for the next 20 years (Energy Outlook 2030) it is worth having a look at to see what they predict. Bear in mind that this is only one company prediction, yet nevertheless it is an influential one.

The report is very briefly summarized in the introductory speech by Bob Dudley, the Chief Executive, who chose the following highlights:
• Global energy growth will average 1.7%, but will be generated by non-OECD nations, while demand from OECD will remain relatively stable.
• Oil supply will grow at around 1% per year, with major increases in supply coming from OPEC, particularly Saudi Arabia and Iraq.
• Coal use will grow at an average of 1.2% per year, largely through demand for power from non-OECD nations.
• Natural gas will be increasingly used as a power source, with demand growing at 2.1% per year.
• Renewable energy sources will continue to be favored, with growth being at around 8% per year, and with demand for biofuel tripling over the two decades.
• Deeepwater production of oil will rise from 7% of the global demand to 9% by 2020.

Those were the initial highlights, and there is slightly more detailed summary at the BP website. Since the booklet that summarizes the data is some 30 pages long, but uses a considerable number of graphics to show the projections, let me borrow some of these to summarize what I see as some of the critical points (and I will add a few editorial comments as I go).

The review (which is the first of its type that BP has released) recognizes that the face of energy consumption is changing. As the world population continues to grow, the shift in energy intensive industries to the developing countries has shifted the locations where demand will grow. Since industrialization also increases the energy use by their populations, there is a compounding rise in their energy use.

Projections of population and Energy Growth (BP Energy Outlook)

What is more interesting to me is how they see how this energy will be supplied. The overall projection is shown in this chart:

Projected future source of Energy Supplies (BP Energy Outlook)

The fastest growing of these segments is that of renewables (which includes biofuels). This can be seen more explicitly in this graph from the report:

Sources of Future Energy Supply (BP Energy Outlook)

The growing impact of renewable energy production will affect both electricity generation, and transportation (the latter mainly through biofuel growth).

Looking specifically at the different fuel sources, the report anticipates that oil growth, will be some 16.5 mbd over 20 years, but that this will have to also compensate for about 4.5 mbd of declines in non-OPEC producers. Non-OPEC will, however, see an increase in overall production, the gains coming from about 2 mbd of increased production from oil sands (with the assumption that this is Canadian, since it is not credited to OPEC, of which Venezuela is a member), from the FSU, and from a significant increase in biofuels, only some of which is anticipated to come from the sugar-based ethanol of Brazil.

Sources of future liquid fuel supply (BP Energy Outlook)

In looking at the above chart it is important to recognize the distinction between the FSU and Russia itself, since that country may well start into a decline in production within the year. The increased production will come from places such as Azerbaijan and Kazakhstan.

The second point is that relating to biofuels, where BP note that renewables currently provide 3% of liquid fuel for transport, but that this is expected to rise to 9%. (Within the next 20 years increased rail, electric, hybrid and CNG are not expected to make a material contribution, though CNG use is expected to be about 2%). The concern with biofuel production is that it is virtually all anticipated to come from ethanol. And, as we have just seen with the closure of the Range Fuels plant in Georgia this week, the commercial viability of cellulosic ethanol has yet to be established, challenging not only the BP view of the future, but also that of others. The practicality of further increase in corn ethanol production in the United States is doubtful, giving the rising cost of the raw feed stock (corn). However this is the projection, and increasingly BP expects that biofuels will meet increases in liquid fuel demand (rising to meeting 60% of the growth by 2030). There is, however, an allocation of 1 mbd for increases in refinery gains (which I have discussed earlier) and from natural gas and coal, which perhaps gives some indication of their opinion of this latter effort.

Anticipated size and source of Biofuel production (BP Energy Outlook)

It is the dramatic increase in transport demand, particularly in Asia, that will drive the increased demand for liquids, China alone is expected to pass the United States in oil consumption within this time frame. To further supply that growth, NGL increases of more than 4 mbd from OPEC, and crude oil production growth mainly from Saudi Arabia and Iraq is projected. (In this regard it should be noted that a year ago BP were anticipating that Iraq might be producing 10 mbd by 2020 – the current more realistic target is 5.5 mbd by 2030. And while Iraq has stated it may be able to reach 12.5 mbd by 2017, the condition of the infrastructure in the country, among other issues, would suggest that BP are now more likely correct). Whether Saudi Arabia will rise to the challenge of producing (and likely more critically exporting) at the levels BP projects, given the current age and production history of its main fields is a question, since recent pronouncements from that country suggest a more conservative production capacity of 12 mbd and a disinclination, perhaps, to produce at even that level. (BP assume that both Russia and Saudi Arabia will retain their market share of 12% over the two decades, which, with an assumed total of over 102 mbd would give them each an assumed production of over 12 mbd). To reach the Saudi target BP expect them to expand production capability after 2020.

The major change in fuel use over the next two decades is expected to come in the increasing move from coal to natural gas as the primary source for electricity generation. Because of overall increases in power demand absolute demand for both fuels will increase, but increasingly the demand will shift to NG.

Thus, for example, Chinese growth in demand will rise at 7.6% pa to 43 bcf/day, though this will still only be 9% of their total energy consumption. It is the BRIC countries, which include Brazil, Russia, India and China (and now South Africa) (H/t KLR) whose overall growth in demand, with that in the Middle East, will likely prove greatest over the next two decades.

Expected growth in NG demand in the next 20 years (BP Energy Outlook)

By 2030 BP project that most use of oil for power generation has been displaced, with coal and NG being the primary fossil sources. NG use will increase to about 40% of the market, outside of Europe, where it rises to 65%, given the European concern over climate change. However, in terms of the absolute market, Europe will see a much greater impact from renewable resources generating power, so that the percentage that NG provides will only rise to 24%. Over half the NG supply in North America will come from shale gas and coal bed methane (CBM), elsewhere the impact from those resources will, within this time frame, be much less. Whether or not these unconventional resources reach the 57% market supply by 2030 will likely depend on the development of at least one new technological breakthrough that lowers cost while increasing long-term yield from the wells, but that is a quite feasible assumption.

Electric Power generation by source (BP Energy Outlook)

The market for LNG is anticipated to grow significantly (4.4% pa), particularly in Europe and Asia. Supply is initially seen as coming from the Middle East, but this will be followed by production from Australia which will overtake Qatar by 2020, and then African deposits will come on line providing 41% of the supply by 2030. It is interesting to note the caveat that BP introduce into this projection.

We assume that policy supports the continued rapid growth of non- fossil power generation – especially renewables, which attain a global share of 10% by 2030. Where gas is available at a competitive price, it continues to displace coal.

Regional demand growth for LNG (BP Energy Outlook)

It is the response that China makes in changing their primary source of power as they continue to expand production, and thus energy demand, that will decide how far, and how fast the transition from coal will occur. BP anticipate that the market overall will continue to rise until just before 2030, at which time it will flatten. But whether that happens will likely depend on availability and price, of both coal, and its potential replacements. (Hence the caveat).

BP recognize that this is only a base case projection, and that there are many different factors that will likely change the final results. That is likely to be particularly true if there is an upsurge in interest in climate change legislation and regulation. I have made some comments on how accurately I think that the models have been developed, but that should not detract from the value of this particular document which, being freely downloadable, is well worth getting and saving.