Chapter 4: Natural gas

Natural gas has occurred naturally for millennia, having manifested its presence through natural seepages from underground, which were often treated as much with curiosity as with fear and reverence. The technology to capture, clean up, store and transport natural gas only became available later in the history of the hydrocarbon industry and, hence, natural gas only came to prominence in the second half of the twentieth century. This was helped by the laying, in the 1930s and 1940s, of several pipelines in the United States and, from the 1960s onwards, by the large pipeline infrastructure projects in Europe, such as Brotherhood, which connected the West Siberian fields of the then Soviet Union to Eastern Europe.

As a result, natural gas is considered the newest of hydrocarbons and many people believe it to be the future of energy, at least in the medium-term. In the last 30 years, natural gas has experienced an impressive growth in terms of reserve discovery, field development and production. On the demand side, gas consumption has rapidly expanded to contest coal’s second place as a source of primary energy. This is particularly evident in electricity generation, whereby gas is increasingly becoming the fuel of choice, replacing coal, which is less efficient and more polluting, although coal still remains the less expensive of the two fuels in some parts of the world. 

Physical characteristics and supply

Gas formation is similar to that of oil. Organic matter, which has been compressed and heated for millennia, is the source of all hydrocarbons, including natural gas of course. At greater depths both higher pressure and higher temperatures favour the production of gas over oil. This is why gas is normally associated with deep oil deposits and as the depth increases so does the probability of finding fields which contain almost pure methane. Most gas comes from ‘conventional’ fields, which allow the extraction of the commodity using existing cost-efficient technology. As Exhibit 1 shows, however, there are additional ‘non-conventional’ gas reserves, which are technically more difficult to exploit. Such reserves include: deep gas, tight gas, coalbed gas, shale gas and gas hydrates.[1] 

Of these, shale gas is the one that has captured the imagination of the industry, particularly so in the United States, where the take-off of shale gas exploration and extraction has changed the economics of hydrocarbons not only in the domestic economy, but also on a world-wide scale. The issue of shale gas will reappear in the following sections.

Although often a by-product of oil production, most of the world’s natural gas production comes from dedicated gas fields.  In its ‘dry’ form, natural gas consists primarily of methane (CH4 often up to 90%), small amounts of other hydrocarbons such as ethane, propane and butane, and even smaller amounts of carbon dioxide (CO2), oxygen (O2), nitrogen (N2), hydrogen sulphide (H2S) and rare gases (A, He, Ne, Xe). Gas exploration is similar to, and associated with, oil exploration. Once gas is produced at the wellhead, it goes through a purification process, which removes NGLs (‘wet’ gases, which can be further processed and marketed separately), water vapours, carbon dioxide, sulphur compounds[2] and oil (if the gas is associated with an oil well). This is required for the ‘dry’ gas to be of suitable quality for pipeline transportation and further distribution. A sophisticated network of pipelines[3] is used to collect the gas from the wellhead, channel it through the processing plant for purification, store it if necessary and distribute it to its final destination; or channel it to a port facility for cryogenic liquefaction, load it on specialised LNG carriers, unload it at a regasification facility at the other end and deliver it again by pipeline to its final destination.

Natural gas can be measured in many different ways, which were covered earlier on in Chapter 1. To quickly recap here, for trading purposes, volume is important and, hence, the most common measurement units are cubic feet (cbf or cf) and cubic meters (cbm or cm); gas reserves are quoted in trillion cubic feet or trillion cubic metres (tcf/tcm). For consumption purposes, gas is normally measured in therms or BTUs to reflect the amount of energy consumed. For pricing, probably the most widely used unit is the BTU, in fact $/MMBTU, although pence/therm is the price quotation in the United Kingdom. To calculate its equivalence in other fuels, the amount required to produce a standard electricity unit (e.g. MWh) is used instead.

Reserves and production

Like oil, substantial amounts of gas reserves are held by those who don’t consume them heavily. The picture is similar, but not identical, to that of oil. Reserves are concentrated in a few regions and are controlled by relatively few governments. In 2020, there were 188 tcm (6,639 tcf) of gas reserves in the world and the development of gas reserves since 1980 is shown in Exhibit 2. Of these, 51 tcm (1,801 tcf, 27%) were located in Russia and Turkmenistan, and 75.8 tcm (2,677 tcf, 40%) in the Middle East. Within the latter region, two countries hold the majority of reserves: Iran and Qatar. In fact, combining the reserves of these two countries with those of Russia and Turkmenistan, i.e. the top four reserve holders, they amount to about 57% of the world’s total. It is no wonder then that when these four, together with several more medium-sized and smaller producers decided to found the Gas Exporting Countries Forum (GEFC) in 2001, they sent jitters to all major gas consumers, especially Europeans. Although GEFC still remains a ‘forum’, it will be interesting to observe whether it could ever turn into a ‘gas-OPEC’, especially since the conflict in the Ukraine which saw a collapse in pipeline gas trade flows between Russia and the EU. Relatively smaller reserves are located throughout the world (see Exhibit 3), but the regions that use it most - North America, Western Europe and Asia Pacific - control less than 20% of the world’s reserves. 

The key development in terms of reserves is of course the prospect of non-conventional gas, especially shale gas. What is now termed ‘the shale gas revolution’ in the US, is the culmination of more than twenty years of efforts to make shale gas extraction both technologically and economically feasible. On the technological front, the breakthrough came with the introduction of hydraulic fracturing, or fracking as is more commonly known. Although the process itself is much older, it was with the persistence of pioneers like George Mitchell, who started experimenting since the early 1980s, which eventually made fracking work nearly twenty years later. Aided by directional (e.g. horizontal) drilling to increase accuracy and effectiveness, fracking consists of pumping a high-pressure fracturing fluid in the borehole that has been drilled. The fracturing fluid is typically a slurry of mostly water, with about 10% sand and several chemical additives. The water’s viscosity can be controlled with additives (e.g. guar gum), so that high viscosity fluid is used to cause large dominant fractures, whereas lower viscosity (‘slickwater’) fluid is used to produce smaller, distributed micro-fractures. The sand in the mixture (e.g. silica sand, or other man-made ceramics) is known as the ‘proppant’. Its role is to stay in the fractures and increase the porosity of the shale, so that the gas (and oil) trapped in it can escape more easily and then directed towards a collecting line, which allows the hydrocarbons to rise to the surface. The chemicals in the fracking fluid have a number of uses. Some are there to increase viscosity, others to prevent corrosion and yet others to reduce friction.

The effect of shale gas has been quite dramatic in the energy profile of the US. According to EIA data, currently over 75% of gas produced in the US is shale gas (see Exhibit 4). The immediate effect of this relative abundance was a collapse of domestic gas prices, from a high of ca. $13/MMBtu in July 2008, to an average of $2/MMBtu in 2020, before picking up again in 2022 and then dropping again in 2023. The secondary, and for some more important effect, has been that of consumption substitution. Cheap gas has meant that it is now more price-competitive against coal for power generation, as well as against naphtha as feedstock to the chemical and petrochemical industries. More avenues are sought to absorb shale supply, including the use of LNG for powering trucks (and perhaps ships in the near future) and, ultimately, exports of gas in the form of LNG. With several companies now holding export licences by the US Department of Energy, the US has become in important player in the LNG export market.

Although to date, shale gas has been an exclusively US success story, plans are afoot in several countries around the world to verify the estimated probable reserves and start production, where technologically and economically feasible. In a recent report, the EIA (2015) estimates that the total technically recoverable shale gas reserves amount to over 7,500 tcf (212 tcm). Exhibit 5 shows the geographic location of these reserves, based on the estimates of the EIA report. As one can clearly see, the shale gas potential is enormous, in fact as much as the current conventional gas reserves. However, ‘technically’ recoverable reserves rarely equate ‘economically’ recoverable ones, so it remains to be seen how many of these reserves it will be feasible to monetise.

When it comes to production figures, the world’s two largest producers, by far, are the United States and Russia. Between them, they produced just over 1,600 bcm (billion cubic metres, or 56.5 tcf) of gas in 2023, or 40% of the world output. They are followed by Iran, China, Canada, Qatar, Australia, Norway and Saudi Arabia, while the remaining producers are shown in Exhibit 6. The presence of the US, with 20% of world production, is of course justified, as it is also the world’s largest consumption market. Moreover, the US is also ahead of the game in terms of competitiveness and deregulation and has further increased its production with the shale gas revolution. The salient feature of production, however, is the reduction in the dominance of Russia, which still contributed 14% to the world’s output in 2023. Russia was for many years the dominant supplier of gas to the European Union, before the latter switched to more pipeline imports from Norway and more LNG imports from the USA. Of the remaining producers, Canada directs large quantities of its gas to the US market, Qatar has been impressively active in exporting its gas in the form of LNG and Australia which has also substantially increased its LNG exports to other Asia Pacific economies, so much so that it competes head-to-head Qatar for the crown of the world's largest LNG exporter. All other important producers, perhaps with the exception of Iran, market their production internationally.

The decision to build a pipeline, or use seaborne transportation, is itself complex. Broadly speaking pipelines are more suitable when the distance is below 5,000 km, although depends on the diameter of the pipeline and the annual flow of natural gas in terms of bcm per annum. LNG transportation, on the other hand is more efficient in bringing ‘stranded’ gas reserves to distant markets.

Probably the most interesting aspect of the supply side of gas, as indeed of oil, are the geopolitics and the resultant effects on security of supplies. We have already seen how gas reserves are concentrated in Russia and the Middle East. To complicate matters even more, the supply corridors from producers to consumers are often ridden with problems. Pipelines are the most effective means to move gas from A to B, but they typically have to cross one or more countries, which can often be a headache for all parties involved. More on this, however, later in this chapter.

Demand determinants

Natural gas consumption has experienced remarkable growth; in the last 50+ years since 1965, its consumption has increased sixfold, from 630 bcm to over 4,000 bcm. The average growth rate during these 50 years was 3.5% per annum, compared to the 2% recorded by oil. A host of factors have contributed to this development. The rapid increase in reserves, noted above, certainly provided a springboard for this. The clean-burning properties of natural gas, in the face of increasingly urgent environmental concerns, was another factor. Practically all new fossil power generation projects these days favour CCGT (combined cycle gas turbine) technology.

Increased affluence (at least in developed and rapidly developing economies), combined with an environmental conscience, make gas an ideal choice for the modern consumer. This doesn’t mean that gas’s increased importance has gone unchallenged. During the 2000s, aided by China’s impressive growth of energy demand, coal has again risen to prominence, as seen in Chapter 1. At the time of writing, coal still remains a very price-competitive fuel for power generation, at least outside the US, but more on this in the next chapter.

Gas was first marketed in the USA, in the late 19th century. It was not until the 1930s, however, when technological improvements made possible the laying of high-pressure pipelines over long distances, that it was extensively marketed throughout the country. This started the very long history of gas in the country, which makes it the world’s largest consumer of the commodity; nearly 900 bcm of gas were consumed in the USA in 2022.

In the Middle East the most prominent consumer is Iran with ca. 245 bcm in 2023, practically absorbing most of its indigenous production of 263 bcm. It is a surprise that one of the biggest reserve holders is not a prime exporter, but on the one hand Iranian consumption has practically doubled in the ten years between 2010 and 2020, and on the other the country has been struggling for years to put the investment in place necessary to boost production and become an influential exporter. In Asia Pacific, China and Japan are the two largest consumers, with the former being the most rapidly increasing throughout the 2000s and eventually overtaking the latter in 2009.

In contrast, the CIS uses gas for over 50% of its energy use. In North America (which includes Mexico) the share of gas is  36%, whereas in South & Central America this falls to 23%. In Africa the share of gas is 30%, while in the Middle East, as expected, gas accounts for over 50% of primary energy consumption, the balance being covered by oil. Asia Pacific sources just 12% of its energy consumption from gas, with over 45% coming from coal.

An illustrative contrast is that between Russia and Asia Pacific: in the former, gas has assumed an even more commanding position, accounting for over 50% of total consumption; in the latter gas has a very modest share, with coal still having a stronghold, especially in China and India. Given that this is the key growth region currently and in the foreseeable future, it will be interesting to observe how gas consumption will develop, given that the region as a whole is in deficit, i.e. has to rely on gas imports, particularly from the Middle East. The region is already showing a voracious appetite for any type energy, but as environmental concerns assume urgency, gas becomes a more palatable choice. The development of the Sakhalin II project (LNG) on Russia’s Pacific coast, as well the various offshore gas projects in the Northwest continental shelf of Australia, shows how well aware regional governments and IOCs are of the huge growth potential of Asia Pacific in gas consumption. And from a geopolitical viewpoint, Russia’s expansion to the lucrative Asian markets shows how diversification of consumer markets has become a strategic priority for the country.

Throughout the 2000s, gas absorption by power plants grew cumulatively by over 50%, with more CCGT plants coming into operation. It will be interesting to observe how growth in other sectors, especially the rather negligible transportation, will change the map of how gas is utilised by final consumers.

Storage

Just like oil, gas also has storage requirements. There are various regulatory and economic reasons for doing so. Demand fluctuation has traditionally been one such reason. Increasingly, gas is being used for power generation; uninterrupted power supply requires a steady supply of gas and stored gas helps avoiding disruptions. Typically, two types of storage are required: baseload and peak load. Baseload storage is designed to address long term demand patterns through the consumption year; for example, higher demand in winter months, which implies that gas is injected in the storage during the summer months and retrieved at slow and predictable rates during the winter. Larger depleted reservoirs tend to be used for this storage, which are slower in responding to sudden demand surges. Peak-load storage, on the other hand, is designed for exactly this purpose: sudden demand surges, which require quick delivery of relatively smaller amounts of gas. Salt caverns tend to be used for this type of storage, as well as storage in LNG form.

Trade

Natural gas is not as extensively traded as oil and coal; its physical characteristics make it more difficult to handle and its high flammability makes precision and care imperative. In the 1970s gas entering world trade increased and new countries appeared in the scene, like Netherlands, Norway, Soviet Union, Iran and Mexico. The 1980s saw the opening of the TransMed (or Enrico Mattei) submarine pipeline between Algeria and Italy via Tunisia, the beginning of trade between Malaysia and Japan and the expansion of Soviet gas exports. With the collapse of the Soviet Union in the 1990s, Russian oil and gas exports expanded even more and increasingly larger quantities of pipeline gas found their way to the European Union and the former soviet republics, through which pass the pipelines carrying the gas from the Yamalo-Nenets district in West Siberia to most countries on the eastern EU front. In the meantime, Japan became the dominant importer of liquefied natural gas, a position it still holds today. In the 2000s, there were two notable developments, which affected international trade in gas: the rapid ascent of Qatar to become the world’s second largest gas exporter (mostly as LNG); and the advent of US shale gas, which changed the industry dynamics, not only in terms of production, but also in terms of the direction of trade flows.

In 2023, ca. 30% of the world production entered international trade; the remainder was consumed domestically. World trade amounted to a total of 1226 bcm in that year, with about 55% of it being via pipeline and 45% as LNG. Exhibit 13 shows an overview of the major pipeline gas trade flows, while Exhibit 14 shows the key LNG flows. Following that, Exhibit 15 lists the key gas exporters in terms of pipeline and LNG flows, whereas Exhibit 16 shows the key importers.

Pipelines

Over 675 bcm of natural gas was exported by pipeline in 2023, representing ca. 17% of the total gas produced for that year. Pipeline exports are predominant between Canada and the United States (79 bcm southbound and 28 bcm nothbound), and between Russia and Europe (50 bcm, dramatically reduced from 2020). In addition, another 25 bcm were exported to other CIS countries, mainly Belarus. Pipeline gas also flows in large quantities from Norway (110 bcm, most of it [85 bcm] to the EU to replace Russian gas), Algeria (30 bcm), Netherlands (18 bcm) and the UK to Europe. The other growing force in pipeline exports is Turkmenistan. This former soviet republic typically exported ca. 20 bcm a year, mostly to Russia and Iran. However, in 2007 the country signed a 30-year contract to supply gas to China, and the gas started flowing in 2010. This has now become Turkmenistan’s biggest export flow. Of the 40 bcm exported in 2023, 30 bcm were destined to China, with the remaining piped to Russia and other CIS countries.

As mentioned earlier in this chapter, a pipeline is the most obvious technology choice for transporting natural gas. Methane is carried in its natural gaseous form, with only the need to have compression stations at regular intervals, in order to maintain adequate pressure that will keep the gas flowing. The capacity of the pipeline is dictated by its diameter, so that modern ‘trunk’ pipelines typically have diameters of 48 or 56 inches. Although technically less demanding that a liquefaction plant, pipelines are expensive to lay, especially where the terrain is challenging. More importantly, laying a pipeline assumes that supply of and demand for gas will last for several decades, so that investing in a fixed transportation medium is economically justifiable.

Even more crucial than the technical and economic aspects is the geopolitical significance of pipelines. A case in point is Russia, most of whose gas production was channelled to its most important EU customers via third countries. One of these pipelines is the Yamal-Europe, which carries the gas through Belarus and Poland, before reaching its main customer, Germany. Exhibit 17 shows the path of this pipeline, together with the compressor stations along the way.

The standoff between Ukraine and Russia in late 2005, whose Soyuz/Brotherhood gas pipeline crosses through the former, is well documented and exemplifies the type of political tensions created. In 2013, a way forward appeared to have been found, which involved considerable negotiations between the two countries. Ukraine suspended a deal on closer EU ties and signed an aid agreement with Russia instead. However, developments in 2014 quickly overturned the status quo yet again. The pro-Russia Ukrainian government was ousted, a new pro-EU government was voted in and the treaty with the EU was quickly signed. At the same time, Russia annexed Crimea and there is currently continuing conflict in the eastern provinces of Ukraine, between government forces and separatist groups that wish to maintain their alignment with Russia. At the time of writing, there is no sign of a permanent resolution to the situation.

Another example, in the same vein, is Russia’s decision to lay a new major pipeline to West Europe on the seabed of the Baltic, rather than through the territories of old foes. This refers of course to the Nord Stream pipeline project (jointly owned by Russia’s Gazprom and Germany’s Wintershall and E.On, Netherlands Gasunie and France’s Engie), which started operating in 2011. The project directly links Vyborg in Russia to Greifswald in Germany using twin pipelines, 1,224km-long, 45-inch (115 cm) wide, with a total capacity of 55 bcm per annum. Exhibit 17 shows Nord Stream, alongside other gas pipelines in the region. Following the success of Nord Stream, a second pipeline, Nord Stream 2 started being built, after a further agreement was signed between Germany and Russia. This caused friction both between Germany and some of it EU partners, but mostly between the USA (under the Trump administration) and Germany. Despite the political skirmishes, Germany and the USA reached a deal in July 2021 which would have allowed the pipeline to be finished, on the proviso that the two countries will continue working on ways to mitigate Russian energy dominance in Europe and prevent Moscow from using energy as a weapon in Ukraine and other countries in the region.

At the time of writing, pipeline geopolitics are still firmly at the forefront of European energy policy. The two Nord Stream pipelines had aimed to secure uninterrupted supply of Russian gas to Europe, by linking Russia directly to Germany and by-passing Ukraine. With the on-going conflict in the Ukraine, flows of gas have ceased altogether in Nord Stream, after the pipeline was sabotaged in September 2022. Russian gas still flows to the eastern border of the EU, although these flows are much reduced compared to earlier years. Even more so that before, the EU embarked on a frantic effort to secure alternative sources of gas supply, in order to counterbalance the shortfall from the disrupted Russian gas imports. To this effect, the EU has explored alternative sources of pipeline gas from the Caspian region, particularly from Azerbaijan, which is the most viable alternative at the moment.[4] One such alternative, the Nabucco pipeline, is all but defunct due to lack of funding. Instead, the Trans-Adriatic Pipeline (TAP), in combination with the Trans-Anatolian Pipeline (TANAP), was selected as the preferred route for Azeri gas exports from the Shah Deniz field in the Caspian Sea. In the meantime, Russia gave up in 2014 its South Stream pipeline project which would carry its gas via the Black Sea to Bulgaria and from there to Serbia, Hungary, Slovenia and eventually the north of Italy. Russia does not remain inactive of course. As Nord Stream 2 never started and Nord Stream 1, Russia is trying to strengthen its links with other countries. Turkey has been importing substantial amounts of Russian gas and continues to do so via the Turk Stream and Blue Stream pipelines which cross the Black Sea. In the east, gas flows have commenced through the Power of Siberia pipeline, which links eastern Siberia to northeast China (see Exhibit 19).

As can be seen from the graphic, there is convergence of several pipelines to create one very big flow from the southeast to the northeast of the country. This reflects the concentration of large cities and conurbations in the northeast, where both gas and electricity are consumed in large quantities. Equally, the location of some of country’s biggest gas producing states, Texas and Oklahoma, is reflected in the origin of the main gas flow in the same graphic.

LNG

Liquefied natural gas entered international trade in a very modest way in the 1960s. The first experimental voyages with LNG carriers were carried out in the 1950s, but the first commercial trip was in 1964, between Algeria and the UK. A year later LNG cargoes began flowing from Algeria to France, while in 1969, trade between Alaska and Japan was initiated.

An interesting characteristic of the LNG market is the fact that the transport element was traditionally only the last in a long chain of planning decisions that have to be made for any individual project. Still today, LNG ships are probably among the most sophisticated and technology-intensive in the world, with prices in the region of $180-200 million for a ship with a typical capacity of 174,000 cbm, built in the Far East.

LNG projects are extremely capital intensive, usually requiring billions of dollars of funds, of which a substantial part has to be provided by equity holders. Projects are usually set up as joint ventures between developed and developing countries and involve long lead times, usually between 7-10 years. Some of the factors that need to be in place for a project to be successful include: a big enough reserve of gas which is unlikely to be consumed domestically for the next 20 years at least; one or more buyers willing to enter long-term purchase contracts; a host government willing to be flexible on fiscal issues; expertise in technical and safety areas, and; willingness of all parties to view the projects on a long-term, co-operative basis.

These factors will undoubtedly continue being important in the future. However, though the 2000s we have witnessed a gradual, but persistent, increase in the amount of LNG cargoes that move on a short-term basis, as can be seen from Exhibit 21.

This was not a great surprise though. With a lot more buyer interest and more governments willing to export their production, LNG projects took off since the beginning of the new millennium. According to GIIGNL (2024), there were 20 exporting countries in 2023, with a total capacity of 481 mtpa (million tonnes per annum). As seen in Exhibit 22, USA currently holds the largest LNG production capacity at 91 mtpa. Before the recent surge in building this capacity, Australia used to top the table of liquefaction capacity holders, but is now in second place with 87 mtpa. Qatar is in third place with 77 mtpa from 17 trains at Ras Laffan, operated by the two production companies, Qatargas and Rasgas. Over the last decade, both Qatar and Australia invested heavily in these facilities, in order to monetize their large gas reserves and, as we can see in Exhibit 23, they are now the world’s three largest LNG exporters. In the third place comes the USA which has also ramped up its capacity to monetise its shale production through exports. These exports were instrumental in replacing large amounts of the lost Russian pipeline gas imports in 2022 and will probably continue being very important for European gas supply in the coming years.

On the consumer side, there were 193 LNG regasification facilities, including 50 floating ones (FSRUs), with a total capacity of 1,143 mtpa. Figures for regasification facilities are not immediately comparable with those for liquefaction ones. A regasification facility typically comprises one or more docks where LNG vessels can moor in order to offload their cargo, a set of pipelines which carry the gas in its liquid form to cryogenic storage tanks, a number of vaporizers that turn the liquid methane into its gaseous form and finally another set of pipelines that connect the facility to the main gas pipeline grid. What is, therefore, measured is the storage capacity and the nominal ‘send-out’ capacity, i.e. the amount of methane in gaseous form that can be put onto the gas grid, assuming that the regasification plant has a continuous supply of LNG to vaporize. This nominal send-out capacity is also measured in million tonnes per annum (mtpa). On this basis, we can see in Exhibit 23 that Japan is by far the largest holder of regasification capacity, which reflects its position as the world’s largest LNG importer (see Exhibit 24). The other large capacity holder in the region is South Korea, whereas in Europe it is Spain and the UK holding the top two places. The USA, albeit the world’s second largest capacity holder, is a bit of an anomaly. Quite a few of these regasification terminals were built or expanded in the early part of the 2000s, in anticipation of a surge in US gas imports. But then, the shale gas revolution hit the US market and many of these plants remained underutilised. However, with the sizeable expansion of US exports of shale gas, some of these plants have already been converted into liquefaction terminals.

Once an LNG project, including the transport element, is in place the buyer and seller face the risk of operating a successful and profitable venture. Notwithstanding any technical or operational issues, the key risk is profitability. The buyer requires a long-term, steady stream of income; the seller requires a competitively priced, highly marketable, easily transferable commodity. Long-term contracts (LTCs) have, therefore, been the obvious choice for LNG partners. This is not a novelty; iron ore and other mineral commodities have been traded for decades on the back of LTCs. In this contractual arrangement, the seller normally takes the price risk and the buyer assumes the volume risk. LTCs normally have take-or-pay (TOP) clauses, whereby a buyer is obliged to pay for a certain amount of cargo, even if he does not lift it. Often there are destination clauses: the cargo can only be destined to certain markets; it cannot be sold further on, to more lucrative markets. However, as we mentioned earlier, this traditional long-term buyer-seller relationship has been challenged, with more shipments made on a short-term basis and more flexibility added to LTCs to reflect the new market dynamics.

LNG trade accounts for only about 10% of world natural gas production and is rather small compared to trade flows of other energy commodities; but because of the complexity of its transport logistics, LNG flows have been meticulously documented on a voyage-by-voyage basis, since the very beginning in the 1960s. The carriage of the liquid itself is only one of several steps of a carefully planned procedure, which includes carriage of gas from the point of production to the port liquefaction facility; loading; regasification at the port of destination; and transport to the point of consumption.

Natural gas trade, be it by pipeline or LNG, will continue to rise in importance in the next two decades and even beyond. The human race is looking for ways to respond to rising energy demand, as discussed in Chapter 1, while at the same time dealing with less abundant (or some would say ‘scarce’) supply and the need to put the rate of greenhouse gas (GHG) emissions, especially CO2, under some form of control. More and more nations are adding gas to their energy portfolio and in order to achieve this, they will have to resort to trade. Pipelines, despite their shortcomings, will continue being very important. For LNG the issue will always be that of the huge capital outlay required to build the liquefaction and regasification terminals, as well as the ships themselves, in the face of a market that seems to require more flexibility while still operating on the basis of LTCs. This is why new technology solutions are being tried out, such as floating facilities, both for liquefaction (FNLG unit, such as the Prelude which is currently being operated by Shell in the northwest continental shelf of Australia) and regasification (FSRU – floating storage and regasification unit). 

Pricing

Crude oil, an inherently heterogeneous commodity, has managed to settle on a system of benchmark pricing, as discussed in Chapter 2. This creates a global market, allowing of course for transportation costs and regional demand and supply and supply imbalances.

Why all this variety then? Historically, the most challenging issue for the economics of the industry has been the relation of gas and oil prices. Traditionally, gas prices were determined on the basis of its calorific equivalence to oil. This is what is known as oil indexing, or oil price escalation. The rationale behind this system is not difficult to understand. Until the last 10-20 years, gas has been used for the production of peak electricity, i.e. electricity which is produced to respond to short term, sharp peaks in demand and gas has the advantage of being able to produce this at very short notice. A major competitor to gas in such an operation is fuel oil. Although nowadays this may not be true in North America and the EU, it may still be true in Japan. In addition, gas also competes with naphtha as a feedstock to the chemical and petrochemical industry, which is another strong reason to index gas prices on oil. As a result, LNG cargoes destined for Japan are routinely indexed on the JCC.

At the other end of the spectrum of pricing regimes we have gas pricing in an open, competitive market, with a close correlation between the spot price of gas and the next available futures contract (front month). This is commonly known as gas-on-gas pricing and it is the prevalent pricing method in the US. We have already seen how gas flows within the US; to facilitate this movement, the gas pipeline network has a number of hubs, big interchange points, where gas travels through, can change direction, can be bought or sold and also stored if necessary. It is at these nodal points that pricing takes place and this is also the reason why gas-on-gas pricing is also known as hub pricing. The largest and most liquid of them is Henry Hub in Louisiana and the Henry Hub price is the benchmark price for gas in the US.

Exhibits 31 and 32 show the pricing regimes for gas traded via pipeline and LNG, respectively and, as one can see, gas-on-gas is predominant in the former, while also being head-to-head with oil indexation in the latter.

In terms of different regions, North America uses gas-on-gas pricing almost exclusively. Europe, on the other hand, relies mostly on gas-on-gas pricing. In China, Indian sub-continent and the rest of Asia Pacific oil indexing remains strong, followed by regulated (non-market) prices, particularly in China, India, Bangladesh, Malaysia, Indonesia and Vietnam. Finally, African and Middle Eastern countries rely primarily on regulatory pricing, driven by political and social considerations. Exhibits 33-40 compare pricing regimes in some of the key consuming regions.

Conclusion

To encapsulate a market as complex, diverse and exciting as gas in a few pages is impossible. Natural gas is for many the imminent future of energy, in the face of rapidly declining oil reserves and environmental concerns about the use of coal. The industry has progressed by leaps and bounds in the last 30 or so years. It started with the extensive deregulation of the US and UK markets. This allowed for a lot of integrated services to ‘unbundle’ into their constituents, i.e. gas production, transmission, storage, marketing, distribution and ancillary services, and competitive pricing to become more prominent. In Europe progress has been slower, but it is picking up pace. In Asia gas has started playing a bigger role in the large emerging economies of China and India, but there is still plenty of room for development. Gas consumption is also increasing markedly in the Middle East, alongside oil consumption.

Deregulation, however, is only one force for change. Demand increase, especially for power generation; competition between coal, gas and renewables for electricity generation; the rise of Russia as the dominant gas exporter to Europe; pipeline geopolitics; growth in the volume and diversity of LNG trade flows; the potential for additional conventional gas production from Africa; the shale gas revolution in the US and the knock-on effect on world markets; and the rise of the environmental conscience have all acted as harbingers of change. The list can go on and so will our interest in this endlessly fascinating energy source.

References

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EIA (2019). US Underground Natural Storage Data. Energy Information Administration. Accessed online at http://www.eia.gov/dnav/ng/ng_stor_sum_a_EPG0_sat_mmcf_m.htm

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