The new realities of the natural gas market can be seen starkly in the current difference in natural gas pricing on either side of the Atlantic. In the United States, the benchmark Henry Hub gas price has dropped below $3.50/MMBtu. While it is close to, albeit just a shade above last year’s record low, these prices are still some of the lowest seen in North America for many years. But even more surprising is the outlook as winter approaches. Storage is over 95% full, and US gas futures have dropped 40% this year. You can now buy US gas for 2011 on the New York Mercantile Exchange for an average of $4.10/MMBtu, including winter peaks as well as the current summer low.
This contrasts starkly with the received wisdom of just a few years ago, when US gas prices were looking like staying above $10/MMBtu a few years ago. But the promised US shortage of natural gas simply didn’t materialise. LNG cargoes have been left chasing buyers all over the world. Just this week Norway had to sell a ship full of LNG to South Korea, for want of anywhere closer. There has been a recession, it’s certainly true, and demand has fallen in most major markets. But that doesn’t seem to have affected the oil price very much. Brent Crude for December delivery is trading at $82/bbl.
Meanwhile, in Europe, natural gas prices at the UK National Balancing Point, Europe’s closest equivalent to a trading nexus like the Henry Hub in the US, are around $7.50/MMBtu. The UK still has plenty of North Sea gas and receives piped gas from Norway and some LNG cargoes to make up the difference, but the situation grows more serious the further east you go, into the arms of Gazprom and its near-monopoly on supply to some countries. Under increasing economic pressure, Ukraine increased gas prices by 35% in August, to $8.20/MMBtu. The price is unlikely to come down during the forthcoming winter.
The difference between the European and North American gas markets is a startling one, and it is a gap which has opened up only in the past couple of years. People are now actively talking about taking advantage of arbitrage – the US could soon actually be exporting LNG cargoes to Europe! And the difference has been made by US unconventional gas supplies, especially shale gas. The huge Marcellus Shale stretches through Pennsylvania and into New York state; only a stone’s throw from the major cities of the US east coast. It is far easier to export gas from Pennsylvania to New York than to bring it by ship from Qatar.
At the moment it is still far from clear how this revolution in gas production will play out. Critics are keen to point to water requirements for fracturing gas-bearing rocks, and the potential for contamination of aquifers in some parts of the world which are short of potable water. But so far the ecological doomsday scenarios do not seem to have played out in the US, a country where local environmental issues can quickly stop a project in its tracks. Consequently, interest has been quickly gathering in other countries. India is now moving ahead towards shale gas production, and China, perpetually short of energy, especially clean energy, as our feature in this issue discusses, has rapidly moved to its first auction of shale gas licenses. In Europe, some countries, the UK in particular, remain very wary of shale, but Poland hopes to break its dependence on Russian gas and is actively developing its own shales – first gas is expected to be pumped next spring.
Gazprom has been doing its best to talk down shale - as well it might, because there is the clear potential for something as radical as the transformation in the US gas market to happen elsewhere. Middle Eastern LNG producers must also be considering the wisdom of their investments, and whether their abundant gas might be more profitably used in other downstream ventures. This month also marks the commissioning of Shell’s massive 140,000 bbl/day Pearl GTL project in Qatar. Cheap gas and expensive oil surely make a process that can convert one into the other look much more tempting?
Monday 15 November 2010
Tuesday 5 October 2010
A nail in UCG’s coffin?
Underground Coal Gasification (UCG) hit the headlines in Australia for all of the wrong reasons in July. The Department of Energy and Mines (DEM) of the Queensland state government ordered a shutdown of the Cougar Energy UCG facility at Kingaroy, following the detection of benzene and toluene in monitoring bores.
Even though the company quickly managed to establish that the laboratory results – which it had submitted under voluntary reporting rules - had in fact been incorrect, and the Queensland Department of Environment and Resource Management (DERM) acknowledged that when it checked borehole results, levels of the chemicals were lower than permitted levels in Australian drinking water, the damage had already been done. DERM director general John Bradley actually came out and said that; "in all cases these are below the Australian Drinking Water Guideline standards. The maximum level of benzenes detected was 0.7 parts per billion (ppb) compared to an Australian drinking water guideline standard of 1.0 ppb and this was only detected at the Cougar Energy plant site itself. Although it is difficult to compare exposures from drinking water to those in air, by comparison, this is less than 10% of the benzene level in the air of a city street and up to six hundred times less than the air at a suburban petrol station.”
However, in spite of these reassurances, local residents have been up in arms, and the DERM has ordered that Cougar keep the Kingaroy plant closed until the government is “assured that groundwater resources are protected”. The company was forced to lay off staff and has been placed into a parlous financial position. Shares have plummeted to just 2.3 cents, and just as I was writing this came news that the company’s chief financial officer and company secretary Rodney Watson had resigned. The company posted a full year net loss of A$4.1million, up from A$2.9 million for 2008/09, and said that it might not be able to continue as a going concern, as forecast working capital requirements for the next 12 months exceeded its current cash position.
Cougar has placed the blame squarely at the government’s door for its demise, and not without justification, it seems. But if this is what happens even when chemical levels in water are within permitted drinking limits, one can only imagine what would happen if they were not!
Two other companies are also operating UCG bores at pilot plants in Queensland; Carbon Energy at Bloodwood Creek and Linc Energy at Chinchilla, the latter of which we reported on in Nitrogen+Syngas issue 303 (Jan/Feb 2010). While both are still operating, Queensland has imposed a moratorium on new operating licenses and issued Environmental Evaluation Notices to all of the projects. The matter has made its way to the Federal government, where the Green Party is now pushing to amend environmental legislation, while Senate candidate for Queensland and co-founder of the Republican Democrat party Peter Pyke has said that if elected he would fight to scrap UCG drilling country-wide.
As a potentially promising technology to harness coal reserves in a clean and safe way, an environmental scare – even an apparently spurious one - is really the last thing that UCG needed. As delegates at the UCG Partnership conference in London earlier this year told me, it was already difficult enough to try and convince investors in a technology which many had thought a dead end after abortive trials in the 1970s and 80s, but which has been given a new lease of life by modern drilling and computer modelling techniques. With the fate of Cougar Energy fresh in peoples’ minds, that task has just become harder still.
Even though the company quickly managed to establish that the laboratory results – which it had submitted under voluntary reporting rules - had in fact been incorrect, and the Queensland Department of Environment and Resource Management (DERM) acknowledged that when it checked borehole results, levels of the chemicals were lower than permitted levels in Australian drinking water, the damage had already been done. DERM director general John Bradley actually came out and said that; "in all cases these are below the Australian Drinking Water Guideline standards. The maximum level of benzenes detected was 0.7 parts per billion (ppb) compared to an Australian drinking water guideline standard of 1.0 ppb and this was only detected at the Cougar Energy plant site itself. Although it is difficult to compare exposures from drinking water to those in air, by comparison, this is less than 10% of the benzene level in the air of a city street and up to six hundred times less than the air at a suburban petrol station.”
However, in spite of these reassurances, local residents have been up in arms, and the DERM has ordered that Cougar keep the Kingaroy plant closed until the government is “assured that groundwater resources are protected”. The company was forced to lay off staff and has been placed into a parlous financial position. Shares have plummeted to just 2.3 cents, and just as I was writing this came news that the company’s chief financial officer and company secretary Rodney Watson had resigned. The company posted a full year net loss of A$4.1million, up from A$2.9 million for 2008/09, and said that it might not be able to continue as a going concern, as forecast working capital requirements for the next 12 months exceeded its current cash position.
Cougar has placed the blame squarely at the government’s door for its demise, and not without justification, it seems. But if this is what happens even when chemical levels in water are within permitted drinking limits, one can only imagine what would happen if they were not!
Two other companies are also operating UCG bores at pilot plants in Queensland; Carbon Energy at Bloodwood Creek and Linc Energy at Chinchilla, the latter of which we reported on in Nitrogen+Syngas issue 303 (Jan/Feb 2010). While both are still operating, Queensland has imposed a moratorium on new operating licenses and issued Environmental Evaluation Notices to all of the projects. The matter has made its way to the Federal government, where the Green Party is now pushing to amend environmental legislation, while Senate candidate for Queensland and co-founder of the Republican Democrat party Peter Pyke has said that if elected he would fight to scrap UCG drilling country-wide.
As a potentially promising technology to harness coal reserves in a clean and safe way, an environmental scare – even an apparently spurious one - is really the last thing that UCG needed. As delegates at the UCG Partnership conference in London earlier this year told me, it was already difficult enough to try and convince investors in a technology which many had thought a dead end after abortive trials in the 1970s and 80s, but which has been given a new lease of life by modern drilling and computer modelling techniques. With the fate of Cougar Energy fresh in peoples’ minds, that task has just become harder still.
Friday 16 July 2010
Gas remains a hot topic for Ukraine
Ukraine has had a long and troubled history of relations with its northern neighbour Russia, and the trend shows no sign of going away as we move into the 21st century. Since the breakup of the Soviet Union one of the major bones of contention has been natural gas, at first over complaints of non-payment, and then arguments over pricing which several times degenerated into a complete embargo, and it seems to be an issue which refuses to die. For a while it looked as though the deal struck between the two countries’ presidents in January 2009 might have settled things, but it has not prevented Gazprom from continuing to try and exert pressure over Ukraine. Now that there is a far more pro-Russian government in power in Ukraine, Russia is talking actively of a merger between Gapzrom and Ukraine’s state gas company Nefetegas, something which the Ukrainian opposition fear would effectively be a Russian takeover of Ukraine’s gas industry, given the relative sizes of the two companies.
Ukraine’s elections in February this year have delivered a much more Moscow-friendly administration under president Viktor Yunokovych, and a flurry of deals between the two countries has resulted. But
Ukraine’s gas-based chemical producers, predominantly ammonia and urea based, have found themselves on the wrong side of the partnership, and have in the meantime have sent heir costs progressively squeezed as gas prices continue to rise and the government finds itself less and less willing to continue to subsidise them. The Ukrainian prime minister Mykola Azarov has said that he is considering a complete withdrawal of discounts to nitrogen producers in the second half of 2010. At the moment the import price for natural gas from Russia is running at $7.50/MMBtu, and the Ukrainian National Electricity Regulatory Commission is seeking to increase prices to as high as $9.10/MMBtu, going up to $9.70/MMBtu from October, which would put Ukraine very much at the wrong end of the industry cost curve, especially at a time when gas prices in the US are down to $4.00/MMBtu. The industry has tried to talk the government down to $5.40/MMBtu, but it seems to be a vain hope given the prevailing mood in the country. Ukraine’s ammonia sector had already effectively become a swing producer thanks to the gas price deal agreed in 2009, and it is now facing being priced out of the market completely.
Even if the government were inclined to subsidise the ammonia industry, it finds itself in a poor bargaining position. The financial crisis has hit the country very hard; last year the economy contracted by 15%, its worst performance since the fall of the USSR. Heavily reliant on steel exports, Ukraine suffered disproportionately from the global contraction in manufacturing. At the end of 2008 Ukraine went to the International Monetary Fund for a $16.5 billion bailout, but the money was withdrawn last year over allegations of broken budget promises. The Ukrainian government has been left with very little room for manoeuvre, and it has found that the IMG has also been calling for and end to its gas subsidies.
Russia and Ukraine have agreed that any merger between Gazprom and Neftegas should only proceed step by step, the first one being to produce a 50-50 joint venture company to run some of the assets of both countries, such as gas transit pipelines. If Gazprom does come to control Ukraine’s gas transmission, whether it might be able to offer a more favourable deal as a lifeline to Ukraine’s ammonia producers – perhaps in return for an equity stake as it has done in Russia – remains to be seen.
Ukraine’s elections in February this year have delivered a much more Moscow-friendly administration under president Viktor Yunokovych, and a flurry of deals between the two countries has resulted. But
Ukraine’s gas-based chemical producers, predominantly ammonia and urea based, have found themselves on the wrong side of the partnership, and have in the meantime have sent heir costs progressively squeezed as gas prices continue to rise and the government finds itself less and less willing to continue to subsidise them. The Ukrainian prime minister Mykola Azarov has said that he is considering a complete withdrawal of discounts to nitrogen producers in the second half of 2010. At the moment the import price for natural gas from Russia is running at $7.50/MMBtu, and the Ukrainian National Electricity Regulatory Commission is seeking to increase prices to as high as $9.10/MMBtu, going up to $9.70/MMBtu from October, which would put Ukraine very much at the wrong end of the industry cost curve, especially at a time when gas prices in the US are down to $4.00/MMBtu. The industry has tried to talk the government down to $5.40/MMBtu, but it seems to be a vain hope given the prevailing mood in the country. Ukraine’s ammonia sector had already effectively become a swing producer thanks to the gas price deal agreed in 2009, and it is now facing being priced out of the market completely.
Even if the government were inclined to subsidise the ammonia industry, it finds itself in a poor bargaining position. The financial crisis has hit the country very hard; last year the economy contracted by 15%, its worst performance since the fall of the USSR. Heavily reliant on steel exports, Ukraine suffered disproportionately from the global contraction in manufacturing. At the end of 2008 Ukraine went to the International Monetary Fund for a $16.5 billion bailout, but the money was withdrawn last year over allegations of broken budget promises. The Ukrainian government has been left with very little room for manoeuvre, and it has found that the IMG has also been calling for and end to its gas subsidies.
Russia and Ukraine have agreed that any merger between Gazprom and Neftegas should only proceed step by step, the first one being to produce a 50-50 joint venture company to run some of the assets of both countries, such as gas transit pipelines. If Gazprom does come to control Ukraine’s gas transmission, whether it might be able to offer a more favourable deal as a lifeline to Ukraine’s ammonia producers – perhaps in return for an equity stake as it has done in Russia – remains to be seen.
Friday 4 June 2010
A Pearl beyond compare
In spite of finding myself forcibly detained in Doha for a few days by the Eyjafjallajokull volcanic eruption, one of the highlights of my recent trip to Qatar was a visit to the immense Ras Laffan site in the north of the country, where gas from the North Field comes ashore. As well as being home to Qatar’s two huge liquefied natural gas (LNG) projects, Qatargas and Rasgas, and the Oryx gas to liquids (GTL) plant, the largest and most imposing complex on the site is Shell’s new Pearl GTL plant, now nearing completion.
Pearl is an amazing sight, easily dwarfing the two next door LNG complexes, and Shell are quite justifiably proud of it and keen to dwell on its superlatives. It is the largest project ever undertaken in Qatar; the complex’s footprint covers a larger area than Hyde Park here in London – almost as large as Central Park in New York - and it is made up of two million tonnes of steel and pipes – enough, Shell say, to build 2.5 Eiffel Towers every month during the four month construction phase, which occupied an army of 50,000 workers from 50 countries. There is enough concrete to build eight Wembley stadiums, the 67 control servers run 12 million lines of computer code, while 5,850km of control cables alone would stretch from Doha to Tokyo if laid end to end. At the end of the pipe is the immense water treatment facility which processes water from the site (GTL production produces one barrel of water for every barrel of GTL products from reacting hydrogen with oxygen) through pipes several metres across. It is the world’s largest industrial water processing plant with zero discharge capability, and the treatment plant could serve the equivalent of a city of 140,000 people, according to Shell.
Once it reaches peak production next year, Pearl will be producing 140,000 barrels/day of synthetic diesel, as well as processing 120,000 bbl/d equivalent of natural gas liquids and ethane. It will be by far the largest gas to liquids plant ever built, and at a price tag of $19 billion (some say as high as $24 billion), Shell have had to pay handsomely for that privilege.
The next question will be whether it provides Shell with a return on investment. The Wall Street Journal called Pearl “the most expensive gamble on clean fuel in the history of the energy industry.” But is it such a gamble? Shell is reported to have negotiated a gas price with Qatargas that is virtually free, and the company say that at an oil price of $70/bbl it should generate $6 billion per year in profit. Indeed the surprising thing is that no-one else is doing it, given the difficulties western oil and gas majors have had in breaking into regions now largely under the sway of national oil companies, and their consequent focus on alternatives like sour gas and oil sands. However, this overlooks the fact that the major competitor for GTL over the past few years has not been conventional fuels but the opportunity cost of using the gas elsewhere, primarily for sale as LNG. Until the banking crisis of 2007-8, natural gas costs were high and LNG provided the best returns around for gas monetisation. It is the reason why the LNG industry has expanded by leaps and bounds, but GTL is limited to just a handful of projects.
Now however the boot seems to be firmly on the other foot. The rise of unconventional natural gas production has changed the dynamics of the natural gas market. The USA, which was predicted to be a huge importer of LNG by now, is virtually self-sufficient in natural gas. The LNG industry faces massive overcapacity. And with gas relatively cheap and oil still relatively expensive, even at its massively over budget cost Pearl begins to look like a very shrewd investment once again. Nevertheless, the economics is only one of the hurdles. There has been a large scale-up – Pearl is ten times the size of the other SMDS plant at Bintulu, Malaysia. Given the teething troubles that Oryx faced when it started, Pearl may still not be out of the woods just yet. It will be interesting to see next year – assuming that there are no technical issues with the plant – whether the oil and gas industry swings back towards GTL in the way that it did ten years ago.
Pearl is an amazing sight, easily dwarfing the two next door LNG complexes, and Shell are quite justifiably proud of it and keen to dwell on its superlatives. It is the largest project ever undertaken in Qatar; the complex’s footprint covers a larger area than Hyde Park here in London – almost as large as Central Park in New York - and it is made up of two million tonnes of steel and pipes – enough, Shell say, to build 2.5 Eiffel Towers every month during the four month construction phase, which occupied an army of 50,000 workers from 50 countries. There is enough concrete to build eight Wembley stadiums, the 67 control servers run 12 million lines of computer code, while 5,850km of control cables alone would stretch from Doha to Tokyo if laid end to end. At the end of the pipe is the immense water treatment facility which processes water from the site (GTL production produces one barrel of water for every barrel of GTL products from reacting hydrogen with oxygen) through pipes several metres across. It is the world’s largest industrial water processing plant with zero discharge capability, and the treatment plant could serve the equivalent of a city of 140,000 people, according to Shell.
Once it reaches peak production next year, Pearl will be producing 140,000 barrels/day of synthetic diesel, as well as processing 120,000 bbl/d equivalent of natural gas liquids and ethane. It will be by far the largest gas to liquids plant ever built, and at a price tag of $19 billion (some say as high as $24 billion), Shell have had to pay handsomely for that privilege.
The next question will be whether it provides Shell with a return on investment. The Wall Street Journal called Pearl “the most expensive gamble on clean fuel in the history of the energy industry.” But is it such a gamble? Shell is reported to have negotiated a gas price with Qatargas that is virtually free, and the company say that at an oil price of $70/bbl it should generate $6 billion per year in profit. Indeed the surprising thing is that no-one else is doing it, given the difficulties western oil and gas majors have had in breaking into regions now largely under the sway of national oil companies, and their consequent focus on alternatives like sour gas and oil sands. However, this overlooks the fact that the major competitor for GTL over the past few years has not been conventional fuels but the opportunity cost of using the gas elsewhere, primarily for sale as LNG. Until the banking crisis of 2007-8, natural gas costs were high and LNG provided the best returns around for gas monetisation. It is the reason why the LNG industry has expanded by leaps and bounds, but GTL is limited to just a handful of projects.
Now however the boot seems to be firmly on the other foot. The rise of unconventional natural gas production has changed the dynamics of the natural gas market. The USA, which was predicted to be a huge importer of LNG by now, is virtually self-sufficient in natural gas. The LNG industry faces massive overcapacity. And with gas relatively cheap and oil still relatively expensive, even at its massively over budget cost Pearl begins to look like a very shrewd investment once again. Nevertheless, the economics is only one of the hurdles. There has been a large scale-up – Pearl is ten times the size of the other SMDS plant at Bintulu, Malaysia. Given the teething troubles that Oryx faced when it started, Pearl may still not be out of the woods just yet. It will be interesting to see next year – assuming that there are no technical issues with the plant – whether the oil and gas industry swings back towards GTL in the way that it did ten years ago.
Thursday 18 March 2010
Safety, regulatory questions tarnish China’s DME boom
Dimethyl ether has been one of the fastest-growing applications for methanol in the past few years. South Korea’s Kogas is now on the verge of building a large 300,000 t/a natural gas-based DME plant in Saudi Arabia to feed the burgeoning Korean market, while Chinese capacity has advanced by leaps and bounds to almost seven million tonnes per year, allowing them to transform domestic coal into an LPG substitute and cut down on their rising tide of petrochemical imports. DME can be blended into LPG at levels up to 10-20% without any need to alter distribution infrastructure, and as it was also cheaper and cleaner-burning than imported LPG, China took to it enthusiastically. According to the International DME Association (IDA), Chinese DME capacity quadrupled between 2006 and 2008 alone, although such massive overbuilding seems to have moved far in excess of the market, and actual production in 2008 was just 1.8 million t/a, just 30% of capacity.
However, China’s rush to DME has started to come unstuck, and the issue is a familiar one for DME – corrosion of rubber and plastic seals. DME attacks some types of rubber, and dissolves PVC. LPG containers for the Chinese domestic market often have rubber seals, and in 2008 the Chinese authorities began to become concerned about the potential for these to be corroded to the point where potentially devastating gas leaks could occur. The upshot was the issue of an advisory notice in March 2008 by the Chinese General Administration of Quality Supervision, Inspection and Quarantine that domestic LPG cylinders should not be filled with blends of LPG and DME.
The IDA says that at the levels that DME is blended in China its corrosive properties should present no problems, and that in its “informed view”, any problems reported were probably due to faulty valves, product contamination (eg with water) or inconsistent production and mixing standards. The organisation goes on to state: “there is a concern that some blenders have been tempted to use higher than recommended percentages of DME”, encouraged by the cost advantage of DME over LPG. Reportedly some filling stations were blending at levels of up to 35% DME, which is almost certain to cause corrosion problems. This to my mind goes to the heart of the issue, which is essentially one of standards, regulations and compliance. China does not have a happy history of companies complying with standards even where they are agreed and circulated – and another of the major issues for DME in China is that such standards have lagged behind consumer reality. The Chinese government has yet to set national standards for DME/LPG blends in areas such as storage, transportation and blending ratios.
And in spite of the March 2008 ban, companies continued to blend DME. Dongguan Jiufeng Energy, a major supplier in the southern Guangdong Province, was found to have been continuing to defy the ban after it was reported to the authorities by local media, and after a subsequent investigation it was forced to suspend operations for a week in January. The incident has prompted a major crackdown by the Guangdong Provincial authorities.
If the current crackdown on illegal blending has an upside, it is that it seems to have finally prompted movement by the Chinese government towards a national DME/LPG blend standard – work on which had been languishing since 2008 without formal agreement. In February it was reported that the government was consulting with industry over the establishment of a blend standard and this time was attaching “great significance” to the talks, pressing for a draft as soon as possible, according to Zeng Xiangzhao, a member of the LPG Cylinders Committee of the Standardisation Administration of China. Mr Zeng added that replacing the O-ring seals in LPG cylinders with ones resistant to DME would cost about two yuan each ($0.29).
With Chinese DME capacity still rising, agreement on a national standard cannot come soon enough.
However, China’s rush to DME has started to come unstuck, and the issue is a familiar one for DME – corrosion of rubber and plastic seals. DME attacks some types of rubber, and dissolves PVC. LPG containers for the Chinese domestic market often have rubber seals, and in 2008 the Chinese authorities began to become concerned about the potential for these to be corroded to the point where potentially devastating gas leaks could occur. The upshot was the issue of an advisory notice in March 2008 by the Chinese General Administration of Quality Supervision, Inspection and Quarantine that domestic LPG cylinders should not be filled with blends of LPG and DME.
The IDA says that at the levels that DME is blended in China its corrosive properties should present no problems, and that in its “informed view”, any problems reported were probably due to faulty valves, product contamination (eg with water) or inconsistent production and mixing standards. The organisation goes on to state: “there is a concern that some blenders have been tempted to use higher than recommended percentages of DME”, encouraged by the cost advantage of DME over LPG. Reportedly some filling stations were blending at levels of up to 35% DME, which is almost certain to cause corrosion problems. This to my mind goes to the heart of the issue, which is essentially one of standards, regulations and compliance. China does not have a happy history of companies complying with standards even where they are agreed and circulated – and another of the major issues for DME in China is that such standards have lagged behind consumer reality. The Chinese government has yet to set national standards for DME/LPG blends in areas such as storage, transportation and blending ratios.
And in spite of the March 2008 ban, companies continued to blend DME. Dongguan Jiufeng Energy, a major supplier in the southern Guangdong Province, was found to have been continuing to defy the ban after it was reported to the authorities by local media, and after a subsequent investigation it was forced to suspend operations for a week in January. The incident has prompted a major crackdown by the Guangdong Provincial authorities.
If the current crackdown on illegal blending has an upside, it is that it seems to have finally prompted movement by the Chinese government towards a national DME/LPG blend standard – work on which had been languishing since 2008 without formal agreement. In February it was reported that the government was consulting with industry over the establishment of a blend standard and this time was attaching “great significance” to the talks, pressing for a draft as soon as possible, according to Zeng Xiangzhao, a member of the LPG Cylinders Committee of the Standardisation Administration of China. Mr Zeng added that replacing the O-ring seals in LPG cylinders with ones resistant to DME would cost about two yuan each ($0.29).
With Chinese DME capacity still rising, agreement on a national standard cannot come soon enough.
The future of syngas
As we enter a new decade, even if we haven’t quite decided what to call it yet (twenty-teens?), it is a time for looking both backwards, at where we have come from, and forward, at where we are going. The first decade of the 21st century has been a momentous time for the world, but no less so for the syngas-based chemical industry. Even stepping aside from the political fallout from September 11th 2001, major economic and social factors have been and remain at play. If the 1990s were about the collapse and recovery of the economies of eastern Europe and the FSU, and the beginnings of globalisation, the 2000s have seen the rise of China and the beginnings of a global consensus on climate change. What shape will the new decade take? Will we talk about it as the decade that India came of age?
The syngas industry has seen two major reversals of fortune in the “noughties”. Firstly rising oil and gas prices, driven by the new industrialising countries, especially China, began to make what had become the ‘traditional’ business model – of capacity based in remote areas around cheap ‘stranded’ natural gas – begin to look less attractive. Building costs, finance costs, all soared, but feedstock costs in particular began to make other routes, perhaps based around refurbished, written-down plants close to end use markets, look more attractive. All manner of feeds that had once been the mainstay of the industry, from coal to petroleum coke, made a comeback. China embraced coal enthusiastically. Gasification seemed the way forward, with the new environmental concern also promoting biomass and municipal waste as fuel sources. And sky-high oil prices meant that all manner of routes towards liquid products involving a syngas intermediate step, from methanol to olefins to coal to liquids, became attractive propositions.
But in just the past eighteen months, things have taken a dramatic swing back the other way. The recession has cut oil prices back, although still to historically relatively high levels. Demand for liquids can now be met – for the time being – by existing capacity. The impetus for the syngas routes to fuels has dropped away, although some routes still seem to be gaining ground, with methanol and its derivatives taking an ever greater share of the Chinese fuels market. And developments in the gas arena have changed the feedstock game, too. The US move towards shale gas production has removed that import gap we were all expecting. Now the world is awash with LNG cargoes which were once destined for America (indeed, America is still taking them in, but only to store them and sell them on). While ‘stranded’ gas is becoming a thing of the past, there are still lower gas cost locations in the Middle East, Caribbean, and Central and Southeast Asia, and they are back to the fore.
So what can we expect from the coming 10 years? I am beginning to sense that the era of cheap or even free biomass may be coming to an end. Just as syngas developments which had been assuming that petcoke would remain cheap even once refiners saw that they might have a new buyer for it found that they faced a rude awakening, so I suspect that biomass, already expensive because of its low energy density, may – unless heavily subsidised (and that can’t be ruled out) – end up finding only a few niche applications, such as in the Swedish pulp mills that are producing di-methyl ether via methanol. And although moves towards carbon pricing and trade are still fitful and only sporadically effective, as some of our articles this issue show, the writing may be on the wall for heavy, solid feedstocks like coal unless they can afford some kind of carbon capture system. It will be much easier to justify a natural gas-based plant to a government keen to reduce its carbon emissions than a coal-based one.
Meanwhile, shale gas technology is still spreading, and soon Europe and China, and – who knows, perhaps India – may, like the US, find that they are able to produce far more gas again. Shale gas seems to have finally achieved that long-awaited ‘decoupling’ of oil and gas prices. The question is whether that gap will last through another period of high energy prices such as we saw in 2008. I suspect that it might, and I am starting to be convinced that the next decade will see a return to the ‘traditional’ gas-based model of production, for environmental reasons as much as any, but that higher oil prices might see us beginning to concentrate more on the fuel and liquids end uses for syngas-based products.
But of course… I have been wrong before!
The syngas industry has seen two major reversals of fortune in the “noughties”. Firstly rising oil and gas prices, driven by the new industrialising countries, especially China, began to make what had become the ‘traditional’ business model – of capacity based in remote areas around cheap ‘stranded’ natural gas – begin to look less attractive. Building costs, finance costs, all soared, but feedstock costs in particular began to make other routes, perhaps based around refurbished, written-down plants close to end use markets, look more attractive. All manner of feeds that had once been the mainstay of the industry, from coal to petroleum coke, made a comeback. China embraced coal enthusiastically. Gasification seemed the way forward, with the new environmental concern also promoting biomass and municipal waste as fuel sources. And sky-high oil prices meant that all manner of routes towards liquid products involving a syngas intermediate step, from methanol to olefins to coal to liquids, became attractive propositions.
But in just the past eighteen months, things have taken a dramatic swing back the other way. The recession has cut oil prices back, although still to historically relatively high levels. Demand for liquids can now be met – for the time being – by existing capacity. The impetus for the syngas routes to fuels has dropped away, although some routes still seem to be gaining ground, with methanol and its derivatives taking an ever greater share of the Chinese fuels market. And developments in the gas arena have changed the feedstock game, too. The US move towards shale gas production has removed that import gap we were all expecting. Now the world is awash with LNG cargoes which were once destined for America (indeed, America is still taking them in, but only to store them and sell them on). While ‘stranded’ gas is becoming a thing of the past, there are still lower gas cost locations in the Middle East, Caribbean, and Central and Southeast Asia, and they are back to the fore.
So what can we expect from the coming 10 years? I am beginning to sense that the era of cheap or even free biomass may be coming to an end. Just as syngas developments which had been assuming that petcoke would remain cheap even once refiners saw that they might have a new buyer for it found that they faced a rude awakening, so I suspect that biomass, already expensive because of its low energy density, may – unless heavily subsidised (and that can’t be ruled out) – end up finding only a few niche applications, such as in the Swedish pulp mills that are producing di-methyl ether via methanol. And although moves towards carbon pricing and trade are still fitful and only sporadically effective, as some of our articles this issue show, the writing may be on the wall for heavy, solid feedstocks like coal unless they can afford some kind of carbon capture system. It will be much easier to justify a natural gas-based plant to a government keen to reduce its carbon emissions than a coal-based one.
Meanwhile, shale gas technology is still spreading, and soon Europe and China, and – who knows, perhaps India – may, like the US, find that they are able to produce far more gas again. Shale gas seems to have finally achieved that long-awaited ‘decoupling’ of oil and gas prices. The question is whether that gap will last through another period of high energy prices such as we saw in 2008. I suspect that it might, and I am starting to be convinced that the next decade will see a return to the ‘traditional’ gas-based model of production, for environmental reasons as much as any, but that higher oil prices might see us beginning to concentrate more on the fuel and liquids end uses for syngas-based products.
But of course… I have been wrong before!
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