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Recent trends in global gas

Recent trends in global gas

The 2016 was a turning point for natural gas and saw new trends and tendencies in the field

For further information, you can download the pdf version of the report that features a more detailed analysis and further tables and graphs.

pdfGlobal Gas Report 2017

 

Gas consumption

 

Gas consumption growth has averaged 1.5% per year globally from 2010-2016. This has been in line with the growth in energy consumption worldwide. As a result the position of natural gas in the global energy mix has remained unchanged at 22.3%.

While gas consumption has grown steadily, there have been significant variations across years, between regions, and among individual countries. In particular, global gas growth was nearly 2% per year from 2010-13, then slowed to near zero in 2014 before rebounding in 2015 (1.6%) and 2016 (1.6%). This is the result of multiple offsetting trends at a regional and country level, such as the US shale boom coinciding with the European economic slowdown.

For in depth data analysis, figures and case studies, browse the full Global gas report pdf version.

Gas consumption growth

Gas Consumption Growth Snam

Gas prices

 

Through 2016 gas prices declined in Europe (-$1.7/MMBtu) and Asia (-$0.9/MMBtu) while remaining relatively low in North America. In addition to a global convergence in natural gas prices, this also reflects a continued narrowing of gas and coal prices.

The decline in gas prices is driven primarily by market dynamics, namely sustained growth in global supply availability along with weaker demand growth. Meanwhile, the low oil prices also drove down the cost of indexed gas, further contributing to the global downward trend through the first half of 2016 in particular.

Historically, natural gas was a substitute for oil in heating and industrial processes, resulting in the rise in oil index pricing which priced gas against a major benchmark price for oil. As a global market for LNG has developed, and natural gas has become more widely used, oil indexing has been replaced by the practice of pricing gas against a leading benchmark gas price.

This enables gas price linkages across regions and greater pricing liquidity for gas.

Gas reserves and production

 

Preliminary data estimates from Cedigaz indicate that global gas production was essentially stable in 2016. Given that global consumption grew, the differential between production and consumption would largely be due to increased storage withdrawals.

Aside from the 2016 discrepancy between production and consumption, global gas production has generally grown marginally higher than consumption, at a 1.8% average from 2010-15. Overall the growth in global production has been led by the increased extraction of unconventional natural gas in the US, Canada, Australia, China, and Argentina. Unconventional production has accounted for an additional 332bcm production compared with net growth of 49bcm of conventional gas over that period. Of that production growth the US led with 250bcm of growth.

In broad terms, proved reserves – which exclude unconventional gas – have grown in line with global production, at 1.8% per year over the past decade, although the rate has slowed to 0.2% per year since 2010.

However, unproved reserves (which cannot be classified as proved reserves due to technical, contractual or regulatory uncertainties) have grown far more rapidly. According to the IEA, total gas reserves have increased by an average of 7.8% per year since 2011, which has exceeded the growth in both oil and coal total reserves (1.8% and 1.3% respectively). This is driven by the growth in shale production. Because shale gas is extracted far more rapidly than conventional natural gas, by using different techniques, and given greater regulatory uncertainty, the bulk of global shale reserves are classified as unproved.

Growth in unconventional gas production

Gas trade

 

In 2016, the global trade in natural gas grew significantly, and is estimated to have increased by 5.5% (or 57bcm). This compares to stable but low growth in gas trade in 2010-15, which averaged 1.1% per year. Two factors explain this significant shift in 2016:

  • First, LNG trade rebounded significantly (up 6%, 20bcm) given the expansion of Australia LNG exports and the opening of Sabine Pass 1&2 in the US. LNG supply growth in turn drove significant import growth in Asia (up 7.2% or 17 bcm), of which a majority was concentrated in China and India. Middle Eastern countries also continued to expand LNG imports.
  • Second, pipeline trade grew significantly to Europe, within North America, and to China, resulting in an estimated 5% growth for the year globally (35.8bcm). The significant consumption growth in Europe was largely supplied via pipeline from Russia and Algeria, resulting in an 8% growth in trade which had otherwise stagnated as European consumption declined in the previous years. In North America, further pipeline interconnections between the US and Canada/Mexico led to 15% growth in trade, reflecting an ongoing shift to what is in effect one common gas market. And in China the development of cross-border pipelines supported a 13% growth of pipeline imports in 2016.

 

Overall the balance between pipeline and LNG as a proportion of the global gas trade has remained stable since 2010, with LNG at about 30%. LNG is also providing supply security and flexibility for specific markets; for example, both Poland and Lithuania recently opened LNG regasification capacity to diversify from Russian supply.

Natural gas infrastructure

 

LNG

Low LNG trade growth (~2%) has resulted in declining utilization rates over the last five years, with levels similar to a decade ago. Global LNG capacities are growing both for liquefaction and re-gasification at ~5-6% per year, in line with forecasts.

In terms of LNG liquefaction capacity, the greatest recent growth in capacity has come in Australia which has grown capacity from 27bcma in 2010 to 90bcma in 2016. The increased capacity is the result of large scale, megaprojects in Australia, and the development of existing LNG facilities in the US.

Despite LNG liquefaction capacity growth, LNG capacity utilization has failed to keep pace. Utilization levels for liquefaction facilities worldwide declined from 81% to 75% between 2010-15. This has been in part due to the decline in Egyptian gas production, shifting it from an LNG exporter to importer (shift from 10bcma exports to imports), plus a decline in supply from Indonesia (-10bcma), Yemen (-5bcma), and Trinidad & Tobago (-4bcma). Meanwhile, utilization of re-gasification plants in countries that import LNG fell from 33% to 29% between 2010-15, driven by a European consumption decline and the US shift from import to export.

LNG cost structure

Capital costs for LNG liquefaction plants are now falling by $1,000 per tonne of capacity due in large part to the development of US brownfield projects, converting existing re-gas capacity to liquifaction. Meanwhile, at large, new plants, such as Australia’s Gorgon and Ichthys projects, liquefaction costs are between $1,000 and $2,000 per tonne, and are continuing to rise. This is due to a combination of factors, including project complexity, remote locations, additional infrastructure requirements and specific design parameters. Shipping costs for LNG are declining due to greater efficiencies in tanker design and operations: the average cost of a new vessel fell from $1,770 per cubic meter in 2014 to $1,420 per cubic meter in 2015. Meanwhile, substantial additions of LNG shipping capacity has resulted in spot charter rates falling to $40,000 per day from $130,000 per day in 2012.

International pipelines

Cross-border pipeline capacity grew by 10% between 2010 and 2014, though has not grown significantly since. In that period capacity additions totaled 190bcma of gas transmission capacity. The largest recent project was Europe’s Nordstream pipeline, which added 55bcma of transmission capacity to Germany, and a further 55bcma of capacity from Germany to the Netherlands and the Czech Republic, when it was completed in 2012. Asian pipeline capacity has also been expanded recently, with connections between China, Myanmar and Central Asia, especially Turkmenistan. This has added a further 40bcma to transmission capacity, and further pipeline connections are under construction. Other significant capacity additions since 2011 have included West Africa, with 5bcma, and 10bcma of extra capacity between Bolivia and Argentina.

Looking forward, two major multinational pipeline projects under development include the TAPI pipeline, which would link Turkmenistan, Afghanistan, Pakistan, and India with a capacity of over 30bcma; and the Trans-Anatolian pipeline (TANAP), with up to 30bcma of capacity through Turkey to Europe. While the TAPI pipeline has entered the engineering design phase, further political agreements are required before full construction begins. Meanwhile, TANAP is already under construction and is expected to be completed by 2020, along with the Trans-Adriatic pipeline connecting supply through Greece to Italy. Further pipeline capacity of up to 40bcma is under development between China and Russia. However, the timeline for such projects can be long and relatively unclear given the geopolitics involved.

 

Regasification capacity

 

Policy initiatives

 

Government policy initiatives aimed at encouraging greater adoption of gas as an energy tend to be slow to take shape and implement, limiting significant year to year developments. In the past year though two significant policy developments took shape concerning gas consumption growth.

Across multiple governments worldwide, further policy initiatives have moved to set a price for carbon. The number of national or sub-national carbon-pricing initiatives has doubled to 40 since 2011. Around 13% of global emissions are now covered by a carbon price, and this will increase to 23% when China implements its national emissions trading scheme in 2017. The UK increase in the carbon price floor was significant for shifting power production towards gas.

New technologies are being deployed for LNG

 

  recent trends FSRU

Floating liquefied natural gas (FLNG) and floating storage regasification units (FSRU) provide for more flexible, modular solutions to LNG liquefaction and regasification requirements. Both FLNG and FSRUs can access more remote locations, are more scalable, and can require less initial capital commitment due to leasing structures. FSRU capacity has nearly doubled since 2013, growing from 44 million tons per annum (MTPA) to 83MTPA. Much of this capacity has been added to small, developing countries that cannot necessarily support a full scale LNG regas facility.

The rationale for using natural gas in transport instead of oil is two-fold: First, it has a lower commodity cost than oil products, in most markets. Second, it produces less greenhouse gas emissions and localized pollution than oil products, diesel in particular. However, only 4% of energy usage in the global transport sector comes from natural gas. This reflects the fact that the process of new technologies challenging incumbent technologies takes time and investment. Furthermore, the use of gas for transport faces competition from multiple other new technologies, including electric vehicles for ground transport.

Ground transport

In ground transport applications, the capital cost requirements of converting engines and developing refueling infrastructure varies significantly in different regions. For example, in the US, due to typical engine size and limited market scale for the manufacture of gas engine technologies, the cost of a compressed natural gas (CNG) vehicle can be $8k higher vs. a gasoline alternative. In Italy, however, where vehicles are smaller and CNG is more common, capital costs may be less than $2k. Despite fuel savings from natural gas, it can take an average vehicle owner in the US 13 years to payback that premium, vs. 1 year in Italy. Given the need to recover upfront capital costs for gas, vehicles which consume a very high quantity of fuel, such as heavy duty trucks and buses, tend to adopt natural gas more frequently.

Maritime vessels

A critical factor driving greater LNG usage by maritime vessels is the International Maritime Organization (IMO) MARPOL convention limiting sulphur emissions, which in turn is driving national governments to adopt maritime sulphur regulations. Because of the relative low sulphur emissions from gas vs. conventional bunker fuel, LNG enables ships and ship-owners to meet these rules. However, LNG engines are more expensive than conventional fuel oil options ($3-5m incremental cost) and it is costly for ships to convert from existing technologies 30. As the IMO extends its authority to new geographies from 2020 onwards, the use of LNG may grow more significantly, though it will ultimately depend on the total cost of ownership relative to other technologies such as low sulphur oil-based fuels and scrubbers.

The role of policy

Despite these challenges facing gas technologies for both ground and marine uses, natural gas consumption in the global transport sector has been growing by 4.4% per year since 2010. This growth has been led by China due to a set of policy initiatives focused on increasing gas consumption in the sector. This policy support includes a regulated price structure, which has kept natural gas prices at a discount of between 60% and 70% to alternative oil-based fuels.

China has also provided state funding for developing LNG engines and building refueling stations to bring down capital costs, both for road and marine transport. In Europe, the use of gas in transportation has been a source of growth in an otherwise declining market. The role of gas has been supported, in part, through the European Union’s Trans- European Transport Network project, which has encouraged the development of a refueling network for LNG and CNG. Italy is Europe’s largest CNG market, with 1m vehicles in operation.

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updated
03 October 2017 - 18:35 CEST