Product and market characteristics: A promising future?

The composition and quality of natural gas⁸² varies depending on the place of origin. ⁸³ Before natural gas can be used commercially, it must undergo a process to remove undesirable components. After processing, natural gas fulfils the characteristics of a search good as the calorific value (i.e. the heating value)and other parameters affecting distribution and combustion can be readily measured at the delivery point (by using a gas chromatograph, for example), limiting transaction costs. Commercial contracts require that the gas be delivered within a certain specification range. The composition of natural gas (which determines its heating value) may be changed to fit transport purposes (to LNG) or end-use requirements.

Natural gas is a combustible fuel and cannot be recycled. However, following non-energy use, especially when gas is used as a feedstock for chemical products, the resultant products may be recyclable. Production is equivalent to mining and extraction firms, so gas production (extraction) sites cannot be converted to extraction of other commodities. Gas is sometimes a by-product of oil production (associated gas). Gas production companies are often also involved in oil extraction activities. Natural gas processing plants cannot be easily converted and, even if a much easier refining process than oil products is required, separation of natural gas from water and other hydrocarbons may require different treatments and ad hoc equipment.

LNG is natural gas cooled down to approximately -160° Celsius. Once liquefied, its volume is about 0.17% that of gaseous natural gas, meaning its energy density is about 600 times higher.⁸⁴ Furthermore, LNG weighs merely 45% of the equivalent volume of water (IEA, 2004). This gives LNG a volume and weight advantage, making it easier to store and transport. However, liquefaction is highly capital intensive⁸⁵ and storage facilities are required both after liquefaction at the exporting terminal as well as before regasification at the importing terminal (discussed further below).

Compressed natural gas (CNG) is natural gas compressed to a higher pressure (usually 220 atmospheres) and stored in containers designed for that purpose. It is used as a fuel for road transport vehicles, especially in public transport. Its volume is approximately 0.4% that of natural gas at standard pressure (thus its energy density is around 250 times higher).

Storage

Storage is an essential element of the natural gas supply chain for three main reasons:

 Demand variability: it would not make economic sense to build enough production and transmission capacity to meet peak demand.

 Price volatility: storage can be an attractive instrument to hedge against the commercial risk of very high prices during peak demand and limit the market power of suppliers.

 Risk of supply disruptions: as natural gas is often transported over long distances and across national borders, storage provides the possibility to reduce the risk of supply disruptions that may otherwise occur for technical, political or commercial reasons.

Gas storage facilities can be grouped into two categories: seasonal and peak. Seasonal storage facilities are built to store huge volumes of natural gas for peak demand. Peak storage sites are commonly smaller, but are able to react quickly to sudden changes in demand. Storage of natural gas

82 Natural gas “comprises gases, occurring in underground deposits, whether liquefied or gaseous, consisting mainly of methane. It includes both ‘non-associated’ gas originating from fields producing hydrocarbons only in gaseous form, and ‘associated’ gas produced in association with crude oil as well as methane recovered from coal mines (colliery gas)” (IEA, 2004).

83 Consequently the average calorific value of natural gas varies across countries (all in mJ/cm): Netherlands 35.40, Russia 37.83, Algeria 39.17 and Norway 42.51. For 2009, the IEA (Golden Rules, 2012) estimates the global average gross calorific value of natural gas at 38.4 mJ/cm (at 15°C at a pressure of 101.325 kilopascals).

84 Also, “the composition of LNG is usually richer in methane (typically 95%) than marketable natural gas which has not been liquefied. … Calorific values for re-gasified LNG range from 37.6 mJ/cm to 41.9 mJ/cm” (IEA, 2004).

85 Chevron’s Wheatstone LNG project in Australia is budgeted at A$29 billion. Construction began in late 2011;

first LNG shipments are expected for 2016.

in unliquefied and uncompressed form has huge space requirements, and storage costs are site-dependent. Commonly used sites are (1) depleted oil and gas fields (a cost effective option, especially used for seasonal storage), (2) acquifers, and (3) salt cavities (relatively small but very good withdrawal rates allow for peak shaving activities) (IEA, 2004). Storage above ground is relatively rare, with LNG storage facilities being a notable exception.

The key characteristics of storage are summarised in Table 31. Working capacity is the amount of gas can be injected, stored and delivered in a given storage site. Deliverability refers to the rate of injection and withdrawal per unit time, here expressed as million cubic metres per day.

Table 31. Key storage characteristics

Source: Le Fevre (2013).

LNG offers potential for storage, as gas in its liquefied form has a much better energy per unit of volume ratio. Liquefaction is costly, however, and gas would need to be permanently kept at around -160° Celsius. LNG storage is thus mainly used for peak shaving. Note that LNG import and export terminals also contain storage, which may add to their business case as traders can exploit the storage.

Storage facilities require significant amounts of ‘cushion gas’ to maintain the required operating pressure, which adds to the capital costs of a storage project (Table 32).

Table 32. Typical capital and operating costs for storage facilities

Source: Le Fevre (2013).

Investments in storage are not necessarily market-driven. In response to the January 2009 gas crisis, for example, the European Union has adopted a gas supply security regulation, stipulating that EU member states have to be able to deliver gas for at least 30 days of average demand, as well as in the case of an infrastructure disruption under normal winter conditions. Gas storages were identified

as a vital means to meet this target. In addition, storage facilities are needed to ensure the safe operation of the gas transmission and distribution networks. They may also serve market developments by providing ‘wheeling, parking and loaning’ at major interconnections, for example.

Storage is also for commerce, such as for the management of take-or-pay contracts (Le Fevre, 2013).

Production and international trade

Production of natural gas has more than tripled since 1970, and it continues to grow as new sources are explored and new technologies improve extraction practices. As with other standardised commodities with full control over supply, production and consumption have been growing without significant imbalances (no more than a 2% of global production per year in over 40 years).

Figure 64. Natural gas production and consumption balance, 1970-2012 (bcm, % rhs)

Source: Author’s elaboration from BP stats.

The most important gas-producing countries in 2011 were the US (651 bcm, roughly 20% of global production) and Russia (607 bcm, or 19%) (Figure 65). Other notable producers were Canada (4.64%), Qatar (3.5%), Iran (5.65%), Norway (3.03%), China (3.15%), Saudi Arabia (2.76%), Indonesia (2.38%) and the Netherlands (2.41%). Brazil (0.5%) and India (1.4%) are rather low producers.

Figure 65. World gas supply by region, 2011 (bcm)

Source: Author’s elaboration from OPEC.

Exporting countries, however, are scattered across the world, with Eurasia, Norway and newcomers such as Qatar among the top exporters (Figure 66).

Figure 66. Exports by region (%)

Source: Author’s elaboration from OPEC.

On the import side, while Russian and US imports have declined in line with the growing internal production to achieve a more balanced position in the medium term, European and Asian demand has been increasing in the last five years (Figure 67) as a result of important decisions, such as the end of nuclear energy power in Japan and new Chinese policies to increase energy diversification.

Figure 67. Imports by region (bcm)

Source: Author’s elaboration from OPEC.

As natural gas becomes one of the key sources of energy production in the old continent, European dominance in natural gas imports grows, and so the continent’s dependence on international markets. The international market for natural gas has been growing steadily in the last decade, and in 2011 was worth almost $400 billion (Figure 68).

Figure 68. International trade for LNG, 1999-2011 ($bn)

Source: Author’s elaboration from World Bank, OPEC, and BP. Note: Price used in this chart is a simple average of: Natural Gas (Europe), average import border price, including the UK (as of April 2010 includes a spot price component and between June 2000 - March 2010 excludes the UK); Natural Gas (US), spot price at Henry Hub (Louisiana); and Natural gas LNG (Japan), import price c.i.f. (recent two months' averages are estimates). Data on price collected from World Bank Commodities Database.

The value of today exports is almost 35% of total production value, while in 1999 it was only around 20%. Also due to fast developments in technologies for LNG tankers and gas transportation, natural gas is the market that has experienced the fastest growth (in relative terms) of international trade in the last decade.

Gas reserves and stocks

Technically recoverable natural gas resources are still abundant – totalling 790,000 bcm (Table 33). At 2011 levels of gas consumption, these resources would be sufficient to meet world gas demand for the next 235 years.⁸⁶ Eastern Europe/Eurasia (mainly Russia) and the Middle East together hold 58% of the remaining conventional gas resources, but only 17% of the remaining unconventional gas resources.

Table 33. Remaining technically recoverable natural gas resources by type and region, end 2011 (in tcm)

Total Unconventional

Conventional Unconventional Tight Gas Shale Gas Coalbed methane

E. Europe/Eurasia 131 43 10 12 20

Middle East 125 12 8 4 -

Asia/Pacific 35 93 20 57 16

OECD Americas 45 77 12 56 9

Africa 37 37 7 30 0

Latin America 23 48 15 33 -

OECD Europe 24 21 3 16 2

World 421 331 76 208 47

Source: IEA WEO, 2012.

86 This is, of course, a rather crude estimate, as demand is expected to rise in the future, technically recoverable does not mean economically and environmentally viable, and resource estimates are generally quite uncertain, especially in non-OECD countries.

While there are only limited conventional natural gas resources left in OECD countries, discoveries of unconventional resources (especially shale gas) have radically changed the picture. This holds particularly true for the United States (mainly shale gas), Canada and Australia (coalbed methane), but also potentially in the future for China (huge shale gas resources) and India. Europe also has some shale gas resources (in Poland, the United Kingdom and Ukraine, for example).⁸⁷

As a result of the abundant gas reserves, supply-side elasticity to demand is fairly high in the long term. However, for producers it may be difficult to adjust production levels upwards at short notice (a lengthy permitting process, exploratory seismic work may be needed, drilling and connecting wells to pipelines will take time, etc.). Downward adjustment is sticky as well (reservoir and wellbore characteristics would often not allow simply restarting production later; associated gas depends on combined oil and gas business case).

The impact of abundant supply in the United States, for instance, has caused a sharp increase in the stock-to-use ratio (Figure 69), which may be subject to a rebalance as the supply adjusts to new levels of demand and supply capacity.

Figure 69. US stock-to-use ratio

Source: Author’s elaboration form BP stats.

Gas transportation

Freight costs are significant due to the low energy density and may, in some cases, exceed exploration and extraction costs. Gas trade is still dominated by pipelines, which are characterised by high fixed costs and long lead times. LNG is gaining market share, especially over long distances. Distribution networks require important upfront investments, but they may reduce total transportation costs once the network is up and running.

Pipelines account for 68% of total gas trade (IEA WEO, 2012), dominating gas trade especially over smaller distances. In long-distance high-pressure pipelines (made of steel, with diameters of 40 to 120 centimetres), gas moves at roughly 30 km/h.⁸⁸ Construction costs vary widely both across countries and time, depending inter alia on labour costs and the market price of steel. High fixed costs and long lead times are key, especially when pipelines span over a number of politically unstable countries, and so the transit dimension becomes important (Yafimava, 2011).

87 See also Annex.

88 Source: Total website.

Natural gas can be also compressed to form CNG, which provides the advantage of fewer infrastructure requirements than for LNG and pipelines. The disadvantage is that is requires more space than LNG due to its lower energy density. Thus, while CNG could not compete with LNG at high volumes, it may be a promising transport option for small and remote gas fields (so called

‘stranded gas’). However, seaborne CNG transportation technology has not yet reached commercial scale.⁸⁹

Box 6. Liquefied natural gas (LNG): A long-term solution for gas transportation?

As gas resources are distributed all around the world, and most continents cannot be connected to each other by pipelines, LNG infrastructure will play a central role in determining to what extent the globalisation of gas markets takes place. While pipelines generally remain the most common means of gas trade, LNG is already responsible for 42% of interregional gas trade (IEA WEO 2012). Global LNG trade volumes more than doubled between 2000 & 2010 (JRC 2012), clearly exceeding the increase in gas demand.

LNG regasification terminals are technologically more flexible than pipelines and therefore give less leverage to suppliers. Yet, at the same time, LNG liquefaction facilities are destination-flexible, meaning that producers can, in principle, export to any country with available LNG regasification capacity.

Planning and building an LNG liquefaction terminal takes 4-6 years, and they are expected to run for at least 20 years (with corresponding amortisation). Depending on the assumptions being made about amortisation and discount rates, liquefaction costs some $2-3 per mmbtu. Global regasification capacity represents roughly 2.5 times the global liquefaction capacity (JRC, 2012). There is therefore potential competition for LNG among consumers.

The total transportation capacity of the world’s LNG fleet (some 360 vessels in early 2013), with an average capacity of approximately 150,000 square metres, is around 54 mcm.⁹⁰ Shipping via LNG vessels is relatively fast; while faster LNG vessels may reach some 50 km/h, LNG vessels commonly travel at an average of 35km/h. Shippers may adjust their speed based on their expectations about the development of the gas price. The number of shipping days and the associated time to conclude the transaction between trading partners of course vary widely depending on the distance. Some averages for common trading partners are reported below (transport and regasification costs in brackets; Argus Media):

 1 day for shipments from Algeria to France and Spain (transport and regasification costs per mmbtu: ~$0.15).

 7 days for shipments from Indonesia to South Korea and Japan (~$0.80).

 8-9 days from Nigeria to France or Spain (~$0.90).

 8-9 days from Australia to Japan and South Korea (~$0.90).

 13-14 days from Oman and Qatar to South Korea and Japan (~$1.50).

 20 days from from Algeria to South Korea (~$2.00).

Insurance costs are about 2% of total shipping and storage costs.

Henderson (2012) presents data on the hypothetical case of future large-scale LNG exports from the United States. He assumes liquefaction of natural gas to cost approximately $3/mmbtu.

Transportation on an LNG vessel from the United States to Europe is around $1.3/mmbtu, from the United States to Asia (through the Panama Canal) would be approximately $3/mmbtu. Regasification costs are some $0.4/mmbtu.

89 http://www.investmentu.com/2012/May/cng-natural-gas-transportation.html.

90 More precise data on LNG can be found in Argus Media’s ‘Global LNG’ monthly, for instance.

Table 34. The delivered cost of US LNG exports to Europe and Asia ($/mmbtu)

Note: For the Asian figures Henderson assumes that the Panama Canal will be able to service LNG vessels as of 2014.

Source: Henderson (2012, based on Cheniere Energy data).

Since LNG requires only limited connection to pipelines and, on average, lower investments in infrastructure than for crude oil, costs of transport are a key factor in LNG price. Due to this differential, LNG price has been significantly diverging from benchmark prices (Figure 70), though this difference may stabilise in the future.

Figure 70. LNG price versus US and EU benchmarks, 1960-2012 (nominal prices)

Source: World Bank. Note: Natural Gas (Europe), average import border price, including the UK. As of April 2010 includes a spot price component. Between June 2000 - March 2010 excludes the UK. Natural Gas (US), spot price at Henry Hub, Louisiana

Due to its easy transportability and flexibility to environment with no relevant pipelines infrastructures, LNG demand in areas such as China and Japan has been steadily increasing over the years and these areas have become the main source of demand for LNG global production (Figure 71).

Figure 71. Global LNG delivery (by region; mcm/day)

Source: Waterborne LNG from Rogers (2011).

The future of LNG is still uncertain. On the one hand, sustained demand from the East would keep demand solid for some time. On the other hand, new exploration and discovery of unconventional sources of natural gas may cast doubt on the sustainability of this continuous market expansion.

2.2.1.1 Supply characteristics: A competitive international market

Natural gas is produced in all of the world’s regions. Exploration and extraction of natural gas are capital intensive, as gas producers must sustain initial sunk and subsequent fixed costs (generally somewhat higher for offshore and unconventional gas). For a more detailed discussion, see the section on crude oil.

The gas industry can be divided into three parts – upstream, midstream and downstream.

Upstream activities refer to natural gas exploration and production. The midstream gas business includes the gathering system, processing, compressor stations, LNG terminals, underground storage facilities, as well as the gas transmission grid, hubs and market points. The downstream oil sector is a term commonly used to refer to the selling and distribution of natural gas to consumers. Note that midstream activities are often also grouped with downstream activities.

Upstream industry structures differ widely around the globe. While the United States is best known for its so called ‘(super)majors’ – large ‘fully integrated’⁹¹ multinational oil and gas companies (e.g. Chevron, ExxonMobil, ConocoPhilips, and Hess Corporation) – it is also home to a lot of

‘independents’ – small oil and gas companies focusing on the upstream business (e.g. Apache Corporation, Devon Energy, and Pioneer Natural Resources).⁹² The US historically had regulated wellhead prices which were completely abolished in 1989. Taken together, this creates a truly competitive upstream industry that is able to secure investments in high-risk projects, such as those that eventually resulted in the ‘quiet’ shale gas revolution that was originally driven by the independents. Producers are publicly listed or privately held companies (see 0).

91 The major explore for and produce oil and gas around the world, own pipelines and tankers, and sell these products directly.

92 Canadian producers include Nexen and Vermilion Energy.

In Europe, large integrated oil and gas companies dominate the upstream industry, with smaller independent energy companies being a rather rare phenomenon.⁹³ Apart from the United States and Canadian companies who are often also active in Europe, important producers include BP, BG, DONG Energy, EBN, ENI, OMV, Shell, Statoil and Total. While European producers are generally publicly listed, in some countries governments still own a substantive share (67% of Statoil is owned by the Norwegian government and the Italian government holds a 30% ‘golden share’ in ENI). For most Europe-based producers, exploration and production activities in other parts of the world exceed those in Europe, given Europe’s limited endowment with natural gas.

In most other parts of the world, resource-rich countries usually control oil and gas producers, and they control the largest share of proven world natural gas reserves. Unlike the United States and European majors, their upstream activities are generally focused on their home country. Notable examples in the Middle East include Saudi Aramco, the National Iranian Oil Company, Qatar Petroleum, Iraqi Oil Ministry, Kuwait Petroleum Corporation and Abu Dhabi National Oil Company.

Russia’s most important gas producer is Gazprom, but Rosneft also has significant reserves. Major African gas companies include Sonatrach (Algeria) and Nigerian National Petroleum. Asia is inter alia home to Petronas (Malaysia), Pertamina (Indonesia) as well PetroChina (large shale gas reserves). In the non-US Americas, Pemex (Mexico) and Petroleos de Venezuela feature among the most prominent examples.

In most OECD countries and all of the European Union (as well as parts of the Energy

In most OECD countries and all of the European Union (as well as parts of the Energy

Im Dokument R EPORT OF A CEPS-ECMI T ASK F ORCE (Seite 118-131)