Energy independence – divergent European and American paths meet

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.

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

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.

Not all so rosy for shale gas … …

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.

A recent game of chess in the world natural gas market

A spate of events in the past month has shaped the natural gas markets for years to come. These are the announcements of the supply of Russian gas via the South Stream to Europe and China domestic price initiatives.

A major energy security issue pertaining to the EU has been the supply of gas from Russia. This gas transported via pipelines transit through Ukraine and Belarus. Disputes between Russia and these countries over gas pricing and siphoning have led to temporary shut-downs/ reduction in the gas flow in 2006 & 2007 directly threatening the flow of natural gas to the west European countries.

Figure 1: Nord Stream pipeline

Since then, a new pipeline the North Stream with 20 bcm/ year capacity was laid on the Baltic Sea bypassing Belarus with a first delivery in Nov 2011. Agreement for a second pipeline between Russia and Turkey, the South Stream has also been reached this week. This is expected to bypass Ukraine in transit and underlie the Black Sea transporting 63 bcm/year from 2015. For a long while, this was an impasse with Turkey with the EU-backed Nabucco pipeline in the sidelines. The Nabucco pipeline was meant to transport natural gas from the Caspian region to Europe and reduce its energy dependence on Russia.

Figure 2: South and Nabucco pipeline

However, Azerbaijan and Turkey have signed a gas supply and pipeline contract this week. This is to supply 16 bcm/ year of gas via the Shah Deniz fields via the Trans-Anatolia pipeline, of which 6 bcm/ year is meant for Turkey own domestic consumption. This pipeline is expected to defer the costlier Nabucco project. Further, China and Turkmenistan have signed gas supply and pipeline contracts last month to supply 65 bcm/ year through its remote Northwest. This effectively curtailed the potential supply of gas from the central Asia region to Europe.

This sequence of events has actually lifted Russia’s hand in its gas supply to Europe and shifted its dependence away from the transit countries Ukraine and Belarus. What will be the impact of these moves? Firstly, the monopoly held by Gazprom (Russian main state owned gas company) is expected to strengthen its hands in ongoing negotiations to move away from oil-indexed pricing for gas. Secondly, it will actually hasten the growth of alternative energies in western Europe and may even prompt an unthinkable re-think of the nuclear policy. A third unintended result is the reliance on Iran as the only feasible supplier on the Nabucco pipeline with the ripple effects of potential UN sanctions hanging over.

Another event is China liberalising its well head costs at gas fields and piloting a scheme to liberalise its city-gate gas prices this week. Whilst China has just recently secured a gas supply agreement with Turkmenistan, its phenomenal rate of growth in natural gas use is expected to outpace supply. By liberalising the well head costs at natural gas fields, it is encouraging domestic investment into shale gas and other unconventional gas sources. An EIA survey in 2011 has indicated that China holds probably the largest unconventional gas reserves in the world.

Its pilot scheme in Guangzhou and Guangxi pegs city gate prices to a combination of fuel oil and LPG prices (both liberalised markets in China). Presently, city gate prices are fixed atop a margin on production costs. These city gate prices apply to both domestic and imported gas. These recent measures by China are expected to increase its domestic production much as what USA did over the past 3 years. This can shift its dependence away from imports from Russia and other countries and significantly impact world gas markets. Price reforms are also expected to reduce potential future gas shortages seen in its oil markets.

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

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.