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Energy independence – divergent European and American paths meet

July 25, 2012 2 comments

In recent months, many have touted that the United States is on the road to energy independence. Citibank pointed in the early part of the year that the emergence of shale oil and shale gas and increased vehicle efficiency may make USA the new Middle East of Oil, whilst Philip Verleger, a famed American economist argued that the US will be energy independent in that it will export more oil than it imports by 2023. In March 2012, the United States exports of petroleum products exceeded imports for the first time since six decades.

Whilst the Americans satiate their energy appetite with advanced lateral and horizontal drilling for tight oil and gas, the Europeans are pursuing their own energy agenda via a different route.

Divergent paths to energy independence

The use of gas instead of coal in power generation has reduced American carbon emission by 450 mt over the past 5 years. At the same time, lower energy costs have resulted in a renaissance of industry in the States, with thousands of jobs created and the relocation of petrochemical and fertiliser industries back to the States.

In Europe, countries are adopting a renewables approach towards energy independence instead. Germany’s adoption of Energiewende – an energy turnaround or transformation – faces hurdles to meet all its targets. The Irish targets renewables to be 20% of all energy sources by 2020. These targets are made more arduous by European countries phasing out nuclear power, whilst shale gas lumbers with environmental and geological obstacles in the continent.

Divergent paths meet on transportation

Even as renewables growth accelerates over the next 5 years and natural gas increase its share as an energy source, energy independence in both continents hinges on the key transportation sector. The transportation sector unlike the power sector is made up of disparate millions of vehicles which face inertia to fuel type change relative to more concentrated power stations.

Both continents’ success hinges on reducing the use of gasoline (for America) and diesel (for Europe) in vehicles. The Europeans will largely depend on electric vehicles to wean off oil. However a recent IEA report highlighted the muted impact of electric vehicles – only 5 million of vehicles sold in 2020 or 5% of total vehicles production. It may take another 30 years for electric vehicles to make a material impact, during which re-charging stations and the mileage range of electric vehicles are improved.

The greater abundance of natural gas for the Americans may see it adopt natural gas (CNG / LNG) vehicles as an interim solution for energy independence. However, similar issues arise for this type of vehicles – re-fuelling stations and the mileage range. In the case of natural gas though, prices are not likely to remain at present depressed levels. Advancing renewables technologies on the other hand are likely to see a decrease in unit costs of production over time.

What can international climate treaties do (and not do) actually?

April 5, 2012 Leave a comment

The last few Conferences of the Parties COP have resulted in impasse among the developed and developing countries. Notably the less developing countries highlighted common but differentiated responsibilities amongst the developed countries on carbon dioxide emissions. Whilst developing countries acknowledged the need to curb their carbon dioxide emissions, they also emphasised that it was the economic and industrial development of the developed countries that have brought emissions to its present high level. Developing countries (including the likes of China and India) would not sacrifice the economic development and well being of its populace to reduce carbon emissions. On the other hand, developed countries highlighted the growing emissions of the developing nations (China is now the biggest emitter in the world). Whilst Europe is willing to go it alone, the same commitment cannot be said of other developed countries. Notably the USA would not go agree to any legally binding target without the participation of the developing countries.

Legally binding targets: the be all and end all?

That makes legally binding targets and enforcement – a key objective of international treaties hard to achieve. Negotiations lumbered on with the last COP 17 in Durban hailed as a breakthrough just for a ‘roadmap’ to an agreement in 2015. The difficulties are obvious – the recent EU unilateral move on an airlines tax on carbon emissions invoked threats of trade war and retaliation by China, India, Russia and the USA, with the latter even commenting that it was an infringement on their ‘sovereignty’. Given the nations do not even agree to economic payments of ~$10 million, how likely they will agree on more holistic international agreements?

In an ideal scenario, the international treaties sought to achieve legally binding caps on carbon emissions amongst the nations. These caps would preferably be linked via a global cap and trade agreement as a carrot and stick incentive for nations to reduce their emissions. The objective of a global market for a cap and trade is to assign a price on carbon and thence incentivise carbon abatement programs like renewable energies and carbon sequestration and storage (CCS). Much contention arises on the level of cap for each nation. Too low a level and at which base year would impede its economic growth.

This makes it difficult for carbon intensive countries like Canada to agree to binding agreements. Canada with its vast resources of heavily pollutive tar sands has already backed out of the Kyoto Protocol it originally was a signatory to. Other countries like Venezuela (Orinco heavy oils) and OPEC would have found it equally hard on any agreement. Even Japan with the recent closure of its nuclear plants in exchange for fossil fuels generation will find it hard to replace them in time with renewable energies to meet targets.

Market economics and technological drivers:

What international treaties fail to achieve – that of an equitable carbon price and incentives for carbon abatement projects and development are already been driven at national levels and on bilateral agreement levels. This is more the result of corporate entrepreneurship in response to rising oil prices than environmental conscientious governments.  The EU ETS – a result of the multi-lateral Kyoto Protocol has seen its carbon price fell to a record low of €6.05 in early April 2012.  This was the combination of record corporate investment into renewable energy generation and warm weather that caused an over-allocation of EUAs – a flaw of the cap and trade system that artificially assigns emissions permit quota. Present political discourse is ongoing to reduce the emissions quota so has to increase the EUA price. A higher carbon price is needed to send a strong signal to companies to invest in costlier carbon abatement technologies.

A cost-benefits study of climate change policies recommends a carbon price that slowly increases through the next decade. An initial low price would enable it to pick low-lying fruits (of low marginal abatement benefits). This is increased through the 2020s when more advanced abatement technologies become more economically feasible. A too high an initial price set would create large opportunity costs to other measures of social and economic welfare.

Recent technological advances and economies of scale have however made in some cases –carbon abatement technologies competitive. For example, onshore wind generation in some cases have reached grid parity. Solar PV generation costs have also been drastically reduced and projected by experts to be competitive with conventional electricity by 2015. Generally, on levelised costs of generating electricity basis, onshore generation of electricity costs between $70-225/ MWh. Solar PV electricity costs $200-$300/MWh. Coal generation and gas-fired levelised costs of electricity have cost between $40-$120/ MWh depending on the costs of fuel. See the 2010 IEA electricity generation costs by fuel. Over the past decade, renewable generation of electricity have benefited from subsidies and feed-in tariffs, which provided it initial consumer acceptance and lower costs. It is a victim of its own success now with a cut of the solar installation subsidy in Germany by as much as 29% from 1 Apr ’12 while the tax breaks for wind manufacturers in USA may not be extended beyond end of this year.

Other economic factors are at work in growing renewable generation. With spiralling growth in fuel consumption due to a youthful population, many Middle East countries have seen its crude export volumes drop. Notably Saudi Arabia saw its crude consumption increase from 1.2 in 2001 to 2.6 mb/d in 2011. Several Middle East countries still use expensive fuel oil/ crude oil for electricity generation. If this trend continues, Saudi Arabia may even turn to be a net importer of crude oil however unlikely it is in 2035. The Middle East governments recognise this and are building wind farms and exploiting its sunny conditions for solar power. A recent growth spurt has seen Abu Dhabi establishing Masdar city – an envisioned zero emissions city. See the article Middle East countries have reasons to back renewable energies. Other countries like Egypt and UAE are taking marginal steps towards non- fossil fuels generation (including nuclear generation). Another key reason that OPEC countries are backing renewable energies is that oil is still expected to retain its place as a main primary energy supplier till 2030s as assured by all outlook reports by IEA, BP and Shell.

What incremental benefits of international treaties?

Given the inexorable costs reduction of renewable technologies and its deployment, what will be the incremental benefits of legally binding emissions targets and the artificial market conditions created by international treaties ? It will hasten the development of certain backstop technologies -in particular carbon sequestration and storage (CCS). The CCS has been recognised by IEA as a lever technology to lower world carbon dioxide emissions from 2020s. An estimated carbon cost of €40-50 per tonne will make it economically feasible now, when present price is only €6. However, existing CCS technology is still at a research stage for fixed electricity installations. The only economic use of CCS is in enhanced oil recovery (EOR). The World Coal Association updates a current map of CCS projects.

Another backstop technology that may be promoted is electric vehicles – notwithstanding technologies/ measures like – solar, wind, hydro, geothermal, biomass and energy efficiency programs that are already growing without multi-lateral treaties. Electric vehicles however source their power from power generation facilities. Only if the latter power is from renewable generation will carbon emissions be reduced. Further, due to existing vehicle life span – only 20 million electric vehicles (source IEA) out of 1 billion vehicles is expected to be on the roads. This may reduce an estimated 0.2 Gt of total 30 Gt annual emissions (with transportation contributing ~30% emissions) – not much incremental benefit.

Nuclear energy – it isn’t dead yet

March 15, 2012 Leave a comment

The Fukuskima nuclear accident took place exactly a year ago with a death toll of 19,000. After the accident, Governments around the world shelved new nuclear generation plans, and inspected safety regulations of existing plants.

This proved however only to be a temporary blip in the nuclear industry. Only Japan and Germany have enacted legislation to dismantle existing power plants. In most developed countries, existing nuclear plants are allowed to run till the end of their life spans. A number of developing countries in the Arab gulf, Africa and Asia have also indicated interest in nuclear power generation. Notably, in the USA, the Nuclear Regulatory Commission (NRC) just approved the first nuclear plant since 1978 in Georgia. For an excellent note on nuclear energy post Fukushima, see the IAEE article for a summary.

In this article, the author writes that nuclear energy will still remain an integrated part of the energy portfolio of the future. In fact un-tellingly, it is still important in projected energy scenarios of the future.

Nuclear remains part of the energy portfolio

In the BP energy outlook to 2030 (this was done post Fukushima), nuclear energy share of world primary energy is expected to remain constant at ~7%, even though power consumption is expected to increase 50% from 22,000TWh now. A public website of the IAEA indicates 63 nuclear power plants presently under construction after 13 plants were shut-down during the 2011 accident.

 Growth of world power generation

Growth of world power generation

Key reasons underpin the continued importance of the nuclear energy. Firstly, as a baseload generator of electricity, it complements renewable generation intermittent nature. Advances in technology are also reducing the size and costs of nuclear plants set-up. Notwithstanding that it doesn’t have carbon emissions is also an advantage although the concerns over environmental waste far outweigh this.

Electricity demand during the night and winter is generally higher than during the day and summer in the temperate regions. The former peak load generation accounts for much of the capacity generation which are not well utilised during base load generation. This leads generally to power plants being used at generally low capacity factors of 30-50%, and with consequential higher construction and efficiency costs. The intermittent nature of solar and wind energies do not fit into these electricity usage patterns generally, and need to be supplemented by base load nuclear generation, which operates continuously.

In fact, it is this mismatch in generation and consumption that necessitate energy storage. The latter is presently under much research, with promising advance in hi-tech batteries and hydro-electric storage. Energy storage together with distributed electricity resource systems (DER) are instrumental to the much hyped smart grid technology being employed in future. DERs are small modular energy generation and storage facilities that adjust to the electricity consumption patterns.

Small modular reactors (SMR) may hold the promise of nuclear energy being used in DERs. SMRs are typically 1/10th to 1/3rd of a typical nuclear power plant with ~1 GW. These SMRs have the advantages of lower turn-around time and costs, and being custom built for specific industrial / municipal uses. These come in useful in the uncertain regulatory climate for nuclear energy with approvals often spanning years and costing billions of dollars. A 1GWe of nuclear plant for example costs an estimated $2b. SMRs embed best safety practices used in conventional nuclear plants but has smaller potential hazards with its ‘smaller size’.

Nuclear energy has its past setbacks with the Cherboyl and the Three Mile Island accidents. Lessons were learnt but nuclear energy will stay on in spite of the recent Fukushima accident. The author ends the note with a youtube video on the Fukushima nuclear accident as a testament to its devastation and the loss of lives.

Could shale gas have contributed to the different economic fortunes of Europe and USA?

February 16, 2012 3 comments

In a recent interview of George Soros by CNN, he highlighted that shale gas and shale oil have contributed to the economic recovery of the US. The US ISM manufacturing rose 1% in Jan 2012 over the previous month. Shale gas impacts the economy through:

1.   direct employment and production in gas producing states

2.   lower production costs through power savings and manufacturing feedstock

3.   lower trade deficits and stronger USD; lower inflation

In the main shale gas production states of Texas, Wyoming, Louisiana and North Dakota, towns have been revived and employment is at a country-wide low of 3.3%. It is even reported that McDonald’s in Dickinson provided a sign-on bonus for staff in their outlets. An estimated number is 600,000 people employed in the shale gas industry in a survey done by IHS Insight. In another study by PwC, an estimated 1m more jobs is expected to be created through the middle of the next decade. The PwC study also highlighted several companies like Bayer and Dow Chemical reviving their chemical plants in the shale gas rich regions to appropriate the cheaper feedstock of ethane (in natural gas). Shale gas contributes to almost 40% of daily production 65 bcf of natural gas. This amounts to $29b (at a per mmBtu price of $3) in annual production revenue. Notwithstanding the multiplier effect on the GDP, shale gas impact is much larger than this baseline estimate.

Other unintended consequences of shale gas and oil are a lower trade deficit and a stronger USD. A big story in 2011 is the USA turning to a net exporter of petroleum products. This by far is due to the lower domestic demand and stronger domestic production volumes of oil and gas (shale oil contributed 400kb/d). The dual consequence is to lower core inflation, which directly supports fiscal measures and quantitative easing.

Europe case is different

Comparatively, Europe is still deliberating on the environmental aspects of shale gas drilling. Already France and Bulgaria set a moratorium on shale gas drilling. Further, many of the rosy projections on shale gas in Europe by smaller companies appear too optimistic, and it may take another 5 years for shale gas production in Europe to take off according to Exxon. Among the European countries, Germany and Poland hold the most potential for shale gas reserves and production. See also an article by the author “All not so rosy for shale gas“. Whilst Europe shares US’s concern on energy security, it has traditionally been more environmental conscious than the larger American continent. Not that, energy security is a less pressing issue for Europe with Gazprom having delivered ‘less than enough’ volumes of natural gas to the continent during the cold snap last month.

Would shale gas (and oil) have delivered equal benefits to Europe? Firstly, there are much higher electricity tariffs and diesel/ gasoline taxes in Europe than the States. This is due to the higher taxes (VAT and excise) and feed-in tariffs for renewable generation in OECD Europe. The tables below indicate the household and industry electricity prices in Europe and USA, sourced from the Oil Drum and originally from the IEA quarterly database in 2009. Germany electricity data is not in the figure but in 2011, its residential tariff was $0.178 /kwH on the upper range of the prices. Except for Norway, US has lower electricity tariffs than any European country.

Residential and industrial electricity prices in Europe and USA


A historical comparison between USA and Europe indicates that the USA industrial electricity prices as always below that of Europe. In spite of the increases in fossil fuels (coal and oil) in particular from 2006-2009, industrial electricity prices in USA have remained relatively unchanged in the period.

Comparison of USA and Europe industrial electricity prices


In theory, Europe could have lower electricity prices from cheaper natural gas which contributes about 19% to its power generation. However, it imports almost 35% of its imports from Russia based on take-or-pay long term oil-indexed contracts. This renders it contractually liable to take a minimum amount of gas imports. The imports are mainly on oil-indexed prices which have remained high, although there have been recent pressure to index it on spot gas prices.

This coupled with its higher taxes and feed-in tariffs would have kept its electricity production costs high. Consequentially, it would also not have experienced a similar revival in its chemical industries, based on price parity on the gas feedstock.

The Demand and Supply Cycle of Peak Oil

February 2, 2012 1 comment

Much has been written on peak oil – the theory made famous by Hubbert which now bears its name. In 1972, Hubbert made an analysis that people born after 1965 will see the dissipation of oil use in their lifetimes. Hubbert did not see the emergence of China and its voracious oil appetite in the 2000s. Neither did he see the youthful population growth of the Middle East with its exorbitant oil subsidies. Yet, 40 years later the Peak Oil date has been pushed back time after another.

Peak Oil theory tends to parochially delve into the supply aspect. Hubbert based his theory that oil resources are finite and will eventually be depleted according to a famous bell-shaped curve below.

Hubbert peak oil curve

Peak oil advocates highlight that much of the world oil is supplied by giant oil fields – Ghawar (Saudi Arabia), Kirkuk (Iraq), Cantarell (Mexico) and Burgan Greater (Kuwait), which are rapidly aging. No new major oil fields have been discovered in the past decade. Further, Norway, Mexico and UK join a list of countries which oil production profiles follow the Peak Oil ‘curve’.

The author wrote in May 2011 that the hidden hand of economics is the best answer to peak oil. This can entail a demand and supply cycle of energy resources with an ‘affordable energy concept for all1’ dictated by price as illustrated below:

The hidden hand of economics of Peak Oil

An analysis of trends in the energy sector reveals this hidden cycle at work. There was much public discourse on high oil and gas prices from the mid 2000s that partly arose from high demand in the developing countries. However it is these high prices that have hastened the development of alternative fuels (solar and wind in particular) and the present shale gas revolution. Already, the media has written a lot about about massive shale gas reserves. A massive potential exists too in new technologies eg coal-to-liquids (CTL), gas-to-liquids (GTL) and underground gasification of coal (UGC) that will greatly increase potential fossil fuel reserves.

The CTL and GTL technologies will increase the amount of transportation fuels from the more abundant coal and gas reserves2. These technologies will not be economically feasible without the higher price of oil driving the push for innovation and efficiency. UGC in particular will almost triple the amount of coal reserves, converting underground coal reserves underground to liquid fuels. These new technologies will further push ‘Peak Oil’ later to the future.

Perhaps the greatest impediment to peak oil theory is the use of renewable energy – a potential game changer. According to Bloomberg New Finance in 2011, the total investment in renewables globally reached $260b with cumulative investment of $1t over the past 7 years. It surpassed the investment into fossil fuels for the first time. Most of the investments are into solar and wind energy. It is projected that in 3-5 years, the unit costs of electricity production from PV solar will be able to compete with that from fossil fuels. This is mainly due to the deluge of investment in China into the manufacture of solar panels, which lowers its production costs substantially. Already, the most efficient form of generation of electricity from wind energy is able to compete on a cost basis with electricity from fossil fuels generation.

The increasing oil consumption in the Middle East exporting countries may decrease their available volumes for export over the next decade. Increasing consumption was partly due to subsidies which alone cost $13b in Saudi Arabia in 2010.  This fact has not gone unnoticed in Arabian governments which have embarked on ambitious renewable projects recently. For example, Saudi Arabia is increasing its electricity generation mix of solar to 10% by 2020 to a few GW. Other countries like Oman and Abu Dhabi, and Egypt have embarked on similar solar and wind projects. This spurt of growth is all driven by the rising costs of oil and a need for fiscal balance. Even more interestingly, Qatar has not displayed much enthusiasm in investment in renewable generation – perhaps because of the availability of its own abundant gas reserves.

According to the BP World energy outlook 2035, renewable energy will contribute about 8% of world primary energy consumption. This compares with 1.3% in 2010.

If the trajectory of oil prices continues over the next two decades, expect this ratio to be even higher. Market capitalism will eventually dominate in this efficient allocation of resources.

BP share of world primary energy

Footnote:

1. The chief economist of Bp advocated in the recent statistical review that an affordable energy future for the world population is possible.

2. The reserves to production ratios of gas and coal are approximately 60 and 160 years presently, whilst that of oil is 50 years.

Not all so rosy for shale gas … …

January 7, 2012 1 comment

A rosy scenario has been painted about the emergence of natural gas as a major fuel source.  This was contributed in part by an increase in unconventional gas supply – in particular coal bed methane, tight gas and shale gas. Coal bed methane production is growing but is expected to be important in countries with large coal reserves – Australia and Canada.

Shale gas boom:

Of this natural gas boom, shale gas share of supply has increased to 40% in 2011 from 10% in 2005 in the United States alone. Dick Cheney in 2005 then Vice-President exempted gas drilling from federal regulations. This led to advances in horizontal drilling and hydraulic fracturing and the subsequent boom in shale gas revolution in the United States. Shale gas is expected to contribute to ~13% of total gas volumes in 2035 worldwide under the Golden Age of Gas Scenario (GAS).

Much of the shale gas drilling techniques were attempted by small independents initially. This has contributed to recent boom in shale gas investments in particular with large foreign entities for ‘technological transfer’:

  1. in Dec 2011, a $2.3b joint venture between Total S.A. (25% stake), and Cheaspeake Energy and EnerVest to develop the Utah Shale in Ohio
  2. in Dec 2011, a $0.9b joint venture between Sinopec and Devon Energy for shale gas development in the United States.
  3. in Jan 2012, Marubeni $1.3b joint venture with Hunt Oil to develop Eagle Ford shale resources

This shale gas revolution has spread worldwide. Below is a figure showing the shale gas reserves estimated by the Energy Information Administration.  Presently countries that are investing heavily include China, Argentina and Poland whilst licensing rounds have started in India and Israel.

Figure 1 : World shale gas reserves estimate by EIA

Environmental considerations for shale gas:

However, not all is rosy in this shale gas scenario – in particular environmental and costs considerations have surfaced. Scientists have speculated the following environmental concerns:

  1. Hydraulic fracking possibly causing two separate earthquakes in Ohio and Blackpool, UK, although the link has not been confirmed.
  2. Fracking chemicals leakage to the water aquifer in Wyoming as detected by the Environmental Protection Agency, (EPA). Again the evidence is not conclusive, but this has led to legislation requiring drilling companies to publicise the content of their proprietary fracking liquids. Many in the industry advocated tighter regulations and casings on the drilling as enough to prevent such leakages.
  3. Huge amount of water resources needed for the fracking process. Total volume pumped into a well is from 7500-20000 cubic metres. (source: IEA GAS report)
  4. From well head to burner, shale gas production is also more emissions intensive relative to conventional drilling – although only marginally at 3.5%1 higher than conventional gas production if modern techniques are used. (source: IEA GAS report)

Already, these environmental concerns have led to bans and moratorium in Europe – in particular France, Germany and Britain. Only Poland has been going ahead in the environmental conscious continent.

Project economics:

There is also a lack of price projection and its effect on project economics. With estimated break even costs for shale gas production at about $4 mmBtu2 and present Henry Hub prices at $3 mmBtu3, present production is at a loss. The shale gas revolution is a victim of its own success in the United States. Supply glut is only expected to clear in 2015. A key reason investments still keep flowing is technology transfer and realising that shale gas could be a future revolution.

Notwithstanding these, production over the past 3-4 years is still shedding light on the reserves profile. Presently, a hyberbolic decay profile is assumed whilst in a study an exponential decay is found more appropriate. Total recovery is reduced by half consequentially. Given the short life of existing wells, costly re-fracking may also be needed later. These have important impacts on project economics. Already, reserves estimation in the large Marcellus shale resources has been reduced in a new USGS survey to 84 tcf from a previous 264 tcf by the Department of Energy.

Implications: Higher costs and lesser abundance

The overall implications of these environmental considerations and project economics are potentially higher costs and lesser abundance. However the cause and effect may not be linear. Potential factors include the fast development of LNG infrastructure to link world markets3, and the de-linkage of gas to oil prices outside of the Americas. Maintaining gas prices linkage to oil indices will de-link its own supply and demand fundamentals to gas prices. The construction of LNG terminals will facilitate the export of the gas to markets in Asia, priced at >$10/mmBtu. See the author’s earlier article on a trading hub in Asia. The consequential development of any protocol post 2015 will have a bearing on the relative emissions advantage of natural gas to its substitutes, fuel oil and coal.

1 – Other study reports highlight shale gas emissions (including the higher GWP of methane) to be much higher. This remains a subject of debate.

2 – This estimate figure varies greatly among different well and reports – $2-$6 per mmBtu.

3 – This is progressing at a fast pace worldwide, but still faces obstacles – for example the recent aborted Hess Fall River project.

Singapore as a gas trading hub in Asia: opportunities and challenges

December 25, 2011 2 comments

During the recent visit to Singapore by IEA chief economist Fatih Biroh, he suggested that it can become a regional hub for gas trading. Singapore can capitalise as the major oil trading hub in Asia to be its gas trading hub. This is even as a ‘Golden Age of Gas scenario’ (GAS) heralds in the coming decades.  The opportunities and challenges for this to take place are explored here.

A Golden Age of Gas Scenario:

Presently, some of the largest consumers of gas are in Asia – China, Japan, Iran and South Korea (Source EIA statistics). Considering LNG1 alone, Asia contributes 55% of the world trade presently. Global primary gas demand in the world is expected to increase from 3.3 tcm today to 5.1 tcm in 2035, and accounts for 25% of global energy demand. About 80% of the increases are expected from India, China and the Middle East. (source: IEA GAS report). World trade in gas is expected to increase to 620 bcm in 2035 – divided equally between pipelines and LNG.

In Singapore, oil majors and trading houses have set up gas trading desks. In Feb 2010, a first financially settled LNG swap derivative was created between Citigroup and an undisclosed oil major based on Japan Korea Marker (JKM). The JKM is a daily assessment based index published by Platts, and is the first LNG index in Asia that reflects the supply and demand fundamentals in the region. Generally, LNG prices have been priced off the Japan crude cocktail (JCC, a CIF price of imported crude into Japan including customs tax) published by the Petroleum Association of Japan. The JKM is a physical index for delivery in several Japanese and Korean ports. In Jan 2011, Platts has also introduced gas points off Australia (netback off the JKM), Middle East and the Indian west coast (netback off the Middle East).

The opportunities:

 The increased trading in LNG (from 2% 10 years ago to about 25% of supply recently), is a confluence of a few factors, namely:

  1. A recent gas supply glut worldwide
  2. The recent Fukushima nuclear accident further increasing LNG demand to replace power from displaced nuclear plants.
  3. Increased set-up of LNG infrastructure including import terminals and storage vessels in Asia
  4. The drive to expand energy sources to meet increasing energy needs and security,
  5. Cleaner nature of the gas to meet environmental targets.

In the USA, the Henry Hub settled below $3/mmBtu on the last day of the 2011. This was a drastic change from 2008 when its price was above $10/ mmBtu. A major reason for the worldwide glut in supply is unconventional gas sources contributing 47% of supply in USA and the economic downturn in Europe. This supply glut has increased the availability of spot cargoes in the market, from long term contracts (LTCs).

Most gas contracts are modelled on LTCs Take or Pay (ToP) where the buyers take a minimal contractual volume or otherwise pay a penalty. These LTCs are due to the high capital costs of the greenfields projects and typically last 10-20 years. Almost 95% are based on oil indices. A graph of Henry Hub (HH), the National Balancing Point (NBP) in Britain and the JCC prices is indicated below. Since the past 3 years, the NBP and HH prices have dipped below JCC prices. This incentivises a switch to gas-based contracts and promotes trading that reflects the supply and demand of natural gas.

Preview Changes

Figure 1: JCC, NBP and Henry Hub historical prices

The cleaner nature of the gas (emitting less carbon dioxide per Btu) has also seen its use as a short term measure against reducing global warming. However, the net effect of the displacement of nuclear energy (which doesn’t emit carbon dioxide), and increased usage of gas is still expected to raise emissions to 35 Gt leading to a 650 ppm carbon dioxide concentration and a rise of 3.5 degrees Celsius under the GAS scenario.

The challenges:

In spite of greater trading in LNG recently, challenges remain for a trading hub to emerge in Asia. These are:

  1.   Divergence of gas from oil prices a temporal occurrence?
  2.   Market inertia with LTCs and relative stability of oil prices
  3.   High costs of gas transportation especially LNG freight leading to fragmented markets
  4.   Downstream market regulations

There is no guarantee that gas prices remain low over the long term. In fact, Deutsche Bank estimated that the current supply glut will last till 2014-2015. An excellent paper by Oxford Energy – “Henry Hub at $3 or $20 in 2020?” projects future natural gas price trajectory. It remains to be seen if tightness in the market shrinks LNG trading in the future, as there is less spot cargo “left from ToP” contracts.

However, trading based on gas prices still serves as an independent harbinger of gas fundamentals and a useful tool for risk management. This is tempered by the substitutability of the gas with fuel oil for power generation, LPG for domestic use and naphtha for petrochemicals manufacture.

This substitutability is the original reason for the historical usage of the JCC for gas pricing. The relative lower volatility of JCC to gas prices also encourages its use as a budgeting tool in long term planning, although an averaging monthly index can be created off the spot or forward indices. Consumer inertia by several market players is another reason with several utilities companies in Japan willing to pay a premium for gas for supply stability. Over the next 4-5 years, about a third of the LTCs in Japan are expiring representing a window opportunity for new gas indices to be used.

Existing natural gas markets remain fragmented regionally. There is the main Henry Hub in the eastern seaboard of the United States which is itself separated logistically from the California SOCAL index due to the Rocky Mountains. In Europe, there are a few fragmented gas trading hubs – NBP, the Zebrugge in Belgium and the TTF in Amsterdam.

A key reason for the fragmented markets is the relatively higher costs of transporting natural gas compared to say crude oil. Trading hubs in Europe and USA are inter-connected by gas pipelines, whilst in Asia natural gas is transported seaborne. This requires costlier refrigeration and re-gasification. The increased freight costs reduce the chances of geographical arbitrage taking place across continents unlike that of crude and crude products. It costs an estimated $2.2/mmBtu to transport LNG from the Middle East to Japan (in Sep 11) when the JKM index was ~$18/mmBtu. It must be realised though that large price differences between Europe and the Americas, and Asia have made arbitrage economics frequent in H2 2011 (primarily due to the Fukushima nuclear accident increasing demand in Japan).

Another factor that may hasten gas trading (or not ) is downstream market regulations in the key consumer markets – China, Japan and Korea. China has a recent pilot scheme (in Guangzhou and Guangxi) to liberalise city gate prices (prices sold to utilities companies in cities) although these continue to be priced off domestic fuel oil and LPG prices. The main utility company in Korea, KOGAS holds a monopoly position in the domestic market, while in Japan liberalisation efforts have been shelved.

Strategic efforts/ advantages for Singapore:

Singapore has the advantage as the main oil trading hub in Asia with existing trading infrastructure and expertise. Further, it is geographically centred between the main LNG supplier nations – Qatar, Indonesia and Australia and the main major import nations – China, Japan and Korea. This offers it a transit point advantage.

It has also invested about $1.1B for a multi-user LNG terminal with 3 storage tanks of capacity 0.54 M cubic metres scheduled for completion in 2013. This is the equivalent of 2 to 3 LNG vessels typically having capacities of 0.15 to 0.25 M cubic metres. On average, there are two LNG import vessels into Korea and Japan a day (in 2010). Most of the import capacity is however slated for domestic use with 1.5 mtpa out of the 3.5 mtpa. Thence said, since gas prices are priced off CIF into Japan and Korea where there are higher storage capacities, storage arbitrage plays are not expected to figure importantly for trading in Singapore.

As with any new market, LNG trading is expected to trudge along. The momentum is building however due to the cleaner nature of the gas, increased environmental concerns and set-up of LNG infrastructure in the region.

1 – Gas is transported as CNG, LNG (liquified natural gas) or in pressurised pipelines. Most of the gas imports in Europe and USA are transported by pipelines. In Asia, gas is traded as LNG transportation requiring cryogenic sea vessels, terminals and storage tanks.