By contrast, natural gas is sold by units of energy. Common energy units include Btu, Therms, and Joules. Natural gas produced from a subsurface reservoir contains a majority of methane plus various other heavier hydrocarbons and, undesirably, some impurities. The relative proportion of heavier hydrocarbons versus methane would determine the energy content of the gas when combusted and, thus, its ultimate value to a customer. Customers pay for energy derived from gas, not for a specific volume of gas. 

Uniquely in the United States, where there is an extensive pipeline network with roughly equivalent gas specifications, gas prices were previously quoted by volume (in Mcf). Gas customers in the United States could convert purchased volume to energy equivalents because the calorific values of the pipeline is roughly similar across the network. However, over the past few years, the $/MMBtu pricing methodology is gaining traction in the United States. 

Because natural gas is difficult to transport, natural gas prices tend to be set locally or regionally, not globally as for oil. For the majority of traded natural gas that is transported by pipeline (around 55% of total trade), prices can be set by negotiation, regulation, or open-market mechanisms similar to those used in oil markets. The remaining portion of the natural gas trade is by shipborne Liquefied Natural Gas (LNG). In the LNG market, the majority of the cargoes are sold on a long-term contractual basis at prices either indexed to the cost of feed gas, floating price in the destination market, or indexed to oil or other commodities. 

Where there are many buyers and many sellers of gas, traded prices are most influenced by supply and demand. In countries with deregulated markets, such as the United States and Europe, prices may be set by traders at dedicated physical or electronic exchange which would price gas at location-specific hubs. Outside of United States, hub gas pricing is becoming the pricing standard in Canada, continental Europe, the UK, and parts of Australia – all regions with extensive gas infrastructure, large number of gas sources and gas consumers, clear regulations, and limited government influence on the markets. There have been attempts to create hub prices in other parts of the world, such as Singapore, China, and India; however, until there is the ability to easily and transparently transport gas from these hubs to other regional markets, gas regulations are harmonized, there are sufficient volumes traded on these hubs, and the cloak of secrecy surrounding gas prices in these regions is lifted, it is unlikely that suppliers and buyers outside the local market will want to trade on these hub prices. 

Supply-and-demand factors that can influence natural gas prices include variables such as production levels, gas storage injections and withdrawals, weather patterns, pricing and availability of competing energy sources, and market participants’ views of future trends in any of these or other variables. If the weather is cold and gas is used for space heating in that particular region, then gas prices may rise in the winter months. Conversely, if most of the gas is used to generate power mainly used for air conditioning, then gas demand would rise in the hotter summer months. If gas is used, either directly or indirectly, by industrial consumers, then weather would have a minimal impact on gas demand. Disruptions in gas supply (e.g., due to offshore hurricanes in the US Gulf of Mexico) would limit supplies and thus increase prices. 

World Gas Markets

Natural gas markets around the world can be broadly divided into four main groups. These are shown in figure 1 below.

Figure 1: Global gas markets.


Group 1: Gas-on-gas pricing

In this group, gas prices are set in relation to regional gas supply and demand, where gas competes with other gas – hence the term gas-on-gas pricing. This group includes North America, the United Kingdom, and north-western Europe – the most liberal and traded gas markets in the world. North-western Europe has been added to this group owing to the remarkable transition toward hub pricing that has taken place there since the early 2010s. In a relatively short period of time, much of the gas sold and consumed in this region has switched from formula-based oil product–linked prices to hub gas-on-gas prices. This transition has resulted largely from the development of common regulations, standardised contracts, increased infrastructure, government support, and general market liberalisation. Remarkably, this transition has occurred despite the resistance of major gas suppliers, Russia and Norway in particular, who had benefitted from the previous oil product–linked price regime. 

Group 1 regions are characterised by large numbers of buyers and sellers largely competing without governmental intervention. Gas is traded on open exchanges (such as NYMEX in US), and there are established benchmark or hub prices where pricing information is transparent, readily available, and updated regularly. Infrastructure is openly accessible, and usage fees are either regulated or fairly priced. 

Because North America and, to a lesser extent, the United Kingdom and north-western Europe, have extensive pipeline and gas storage systems with opportunities to both export and import gas from outside the markets, gas can be traded on both current and future contracts. This makes it possible for a buyer to purchase a defined volume of gas, to be delivered at a specified location on the gas grid, at a date in the future, at a price established today. This sophistication allows the gas market to be very efficient by maximising usage of infrastructure and allowing both buyers and sellers to plan their financial future. Risks can be managed; however, a consequence is that short-term gas prices tend to be volatile, continuously reacting to supply and demand. 

An advantage of a highly traded system is that different parties can own different parts of the chain – from upstream to gas processing to pipelines, storage, and local distribution – because pricing is transparent and all services are competitive. In theory, no individual supplier or buyer is able to control prices, and the presence of intermediary parties, such as gas traders, usually results in more efficient markets and lower prices. 

US LNG is exported on a US hub plus cost structure, not formula-linked to oil or oil products; although there have been some attempts at contracting with these indices, they have, so far, proved difficult to implement. 

The following is a typical US LNG export pricing formula: 

PLNG = PUS Hub + feed gas pipeline tariff + energy retainage + liquefaction costs + shipping cost, where: 

PLNG is the price of exported LNG; PUS Hub is the feed gas-on-gas price at a defined hub location, which may be the price at Henry Hub or other traded reference gas price in proximity of the LNG plant or feed pipeline; 

Feed gas pipeline tariff is the tariff paid to a pipeline operator to transport feed gas from the pricing hub to the liquefaction facility; 

Energy retainage is a fee, quoted in monetary tariff or gas volume, that is paid or retained by the liquefaction plant to compensate for in-plant fuel usage (up to 10% of feed gas is consumed by gas-drive turbines to power the compressors for the liquefaction trains) and could also be charged as a percentage of hub prices; 

Liquefaction costs are the fees charged by the liquefaction facility to convert feed gas into LNG, plus any storage or loading fees, which could have fixed and variable components. Only a few LNG projects in the world consume electricity from the local electricity grid instead of using feed gas to drive their liquefaction compressors. This benefits tolling model consumers as they suffer less energy retainage and have an added advantage of having much lower carbon emissions than their peers. Texas LNG is one of the few LNG project plants under development with these ‘green’ credentials. 

At a $3/Mcf (approximately equivalent to $3/MMBtu) feed gas price, US LNG could be delivered to North Asia for less than $8.00/MMBtu and to Europe for around $7/MMBtu, assuming a $2.50/MMBtu tolling fee, 10% retainage, and shipping costs of around $0.75/MMBtu to Europe and less than $2.00/MMBtu to Asia. This price range is significantly lower than costs predicted by new LNG suppliers in Australia and Russia, but higher than break-even prices from legacy projects in South East Asia and the Middle East that enjoy low ongoing costs, depreciated capital costs, benefits from NGL (natural gas liquids) sales and generous tax and fiscal systems. However, note that most legacy projects have very limited potential to increase volumes, and many are facing difficulties in sustaining volumes because of declining reserves. Qatar, with its aggressive expansion plans, has embarked on an aggressive pricing scheme since mid-2020, undoubtedly to secure long-term offtake volumes for its expansion plans. 

Group 2: Prices Indexed to Substitute Energy Prices

The second group of gas markets includes Central and Southern Europe, South Africa, and to a lesser extent, South East Asia. In these markets, there is a limited but growing gas grid. There are some gas storage facilities, and an emerging traded gas market. However, most gas remains priced in relation to other energy such as oil products, coal, or even electricity, explicitly linked by formula under majority long-term contracts. 

The net effect of linking gas prices to oil products, such as diesel or kerosene, is that gas is usually sold at a discount relative to the oil fuel, on an equivalent energy basis. The reasons for this are largely historical because gas production and consumption began after oil and coal markets were established. By linking the markets and ensuring that the formula priced gas at an energy equivalent discount, gas producers could convince reluctant buyers to switch to gas, away from traditional fuels such as oil and coal. Linking also establishes a perception that energy products can be substituted for each other, and when the price of the substitute energy product changes, formula-linked gas prices would also change. 

Predictably, during periods of relatively high oil prices, when oil product–linked gas prices rise more than gas supply-versus-demand fundamentals would suggest, gas buyers question the value and logic of linking these disparate commodities. However, when oil prices are low, as they been since 2019, gas buyers, enjoying cheaper gas prices, have largely muted their complaints and accepted the link even though the rationale for linking prices remained questionable. Nevertheless, the trend toward delinking oil and gas is established and gaining converts and there will be fewer gas markets in groups 2 and 3 in the future. This trend will accelerate as trading companies sell short-term cargoes at negotiated prices with no direct relationship to oil or oil product prices and as US LNG enters traditional LNG markets in Europe and Asia. 

Group 3: Pure Oil-Linked Pricing

This group is largely characterised by the traditional LNG markets of North Asia, especially Japan, Korea, and Taiwan, and emerging LNG markets, such as India and China, which are also following this model. The North Asia region, with the exception of China, has limited domestic energy resources and does not have the infrastructure to import gas by pipeline, so essentially all of their gas is delivered via LNG imports. China has significant domestic production and pipeline imports, but its growing LNG long-term contracted gas is largely priced on oil linkage on the model set by Japan and followed by Korea and Taiwan. 

Prior to the introduction of LNG in the late 1960s, Japanese power utilities relied on imported crude oil and coal for power generation. Similar to the European experience, these risk-averse buyers insisted on a guaranteed discount to persuade them to substitute liquid and solid fuel for LNG sourced from potentially instable and risky countries such as Indonesia and Malaysia. The 1973 oil shock convinced them to take a chance on this new fuel, but only if the LNG prices were guaranteed to be at a discount to current oil prices. Japanese buyers also wanted a ceiling (price cap) so that future oil price shocks would not translate into immediately higher gas prices. In return, Japanese consumers agreed to long-term contracts and a guaranteed minimum LNG price, thereby allowing their credit to be used by the project sponsor companies to fund the export projects. 

The solution to the dilemma was the innovative S-curve concept, which links oil and gas prices by a formula (Figure 2). The horizontal axis of the graph is the weighted average of the crude oil import price. In the case of Japan, this is the Japan Crude Cocktail or Japan Customs Cleared (JCC) price, which is averaged over a period of time, typically one to three months. The vertical axis is the imported LNG price. The relative slope, or angle, of the line gives the relationship between oil prices and LNG prices.

Figure 2: Innovative S-curve linking oil and LNG prices. The straight oil parity line is based on 1 bo = 6 MMBtu and 1 ft3 = 1,000 Btu. Thus, the energy equivalent gas price at $60/bo ≈ $10/MMBtu. 

When the slope of the line is 16.7%, LNG is priced equally to crude oil on an energy equivalent basis, based on 1 bo generating approximately 5.8 to 6 MMBtu of energy. Thus, if the market valued gas and oil on an energy equivalent MMBtu basis, then gas should be priced as 16.7%  oil price. Slopes less than 16.7% imply that LNG is sold at a discount relative to oil, whereas slopes greater than 16.7%, though rare, imply that LNG will sell at a premium price relative to oil. The oil parity line shows that when the oil price is $60/bo, the energy equivalent gas price is $10/MMBtu.

 Typical 'S' curve pricing formula: Plng = A * PCrude Oil + B 

A: The 'slope' linking oil and gas prices. A slope of 16.7% indicates energy equivalent parity between oil and gas prices. Most LNG contracts have slopes between 12% - 15%.

PCrude Oil: Crude oil price. May be a weighted average of a 'basket' of oils, such as Japan Crude Cocktail (JCC) over a defined period, a month or more.

B: A constant added to reflect fixed costs, often related to shipping costs from LNG plant to importing port. 

Many S-curve pricing agreements let the slope change depending on oil price ranges. In these situations, the curve bends at specific oil price points, known as kink points. When oil prices rise above the defined upper kink point, the slope may flatten out, thus reducing the impact of rising oil prices and shielding the buyer from the full impact of rising oil prices. By contrast, when oil prices fall below the lower kink point, the seller is protected because LNG prices would not fall as far as the oil price. Often, the slope of the line would be horizontal below the lower kink point, implying that there is a floor below which LNG prices cannot fall, ensuring a minimum level of income for the seller even if the price of oil collapses. This is often a requirement from the seller’s financiers, who require the project to generate a minimum income to repay the loans independently of falling oil prices. A flat line over the upper kink point would imply a ceiling price. Ceiling prices cap the cost of LNG for the consumer, irrespective of any further increases in oil prices.

In the period from the 1970s to 2000, the S-curve slope was 4%–15%, implying a relatively large LNG price discount to oil, on an energy equivalent basis. As the markets tightened in the period of 2006–8, the slope increased closer to 16% and, in rare cases, exceeded the 16.7% oil-parity threshold. This implied that consumers were valuing oil and LNG equivalently. Because oil prices had previously risen over the $25/bo upper kink point, both the lower and upper kink points were reset to respective thresholds of $40/bo and $90/bo, the new ‘normal’ range for expected oil prices. The oil price decline in 2015–2016 resulted in a drop to around 12%–13%. The introduction of US LNG in early 2016 has further declined the slope of oil-linked contracts from non-US sources, who feel the pressure to discount to maintain market share from the threat of increasing volumes of non-oil price-linked LNG gas from the United States.

In mid-2020, Qatar, seeking to expand its market share ahead of its supply expansion projects, signed a number of long-term agreements at slopes between 10–11%, record low levels. It remains to be seen if this is beginning of a long-term trend or a nadir in gas prices reflecting the pandemic and associated drop in global gas demand.

 How the oil-linked S-curve pricing formula will survive the continuing onslaught of US LNG into the Asia-pacific region is a debatable topic among analysts. The key driver for change would be the relative price of US domestic gas, which determines the feed gas prices for US LNG export projects, versus the global price of oil, which drives non-US LNG prices into North Asia. However, it is clear that the dominance of S-curve LNG pricing is fading, and the future of LNG pricing will involve a healthy mix of different indices and links. 

Group 4: Regulated Markets

Regulated markets dominate much of the world, where gas markets are relatively immature and largely controlled by the state. All infrastructure is owned by the state, either directly or via a national oil company. There is very little private sector involvement in the sale or pricing of gas. 

Gas prices in regulated markets may be set nationally or regionally. The state manages the differences in supply prices, and all supply is added to a pool of gas volumes available to consumers. The state may choose to sell gas at prices less than the average pool price for political reasons. There is no transparency in prices, no active gas markets, and little incentive for private sector investment in supply or infrastructure. If the mandated gas prices are artificially low, as in the Middle East, inefficient consumption of energy often results. Low prices discourage new exploration and production and ultimately may lead to gas shortages and distorted economics. 

China has been included in this group even though the government released new gas pricing formulas linking natural gas price to fuel oil and LPG, because the pricing formula is still set by the state, which continues to own, via its energy companies, most of the infrastructure. Over the next few years, as private enterprises build LNG-receiving terminals and local gas grids, China may move to another group. 

Regulated markets tend to be inefficient because gas is usually priced below its costs, thereby encouraging wasteful usage and decreased investment in exploration and development. Gas subsidies can cost governments large sums of money, do not meet their social objectives, and place price risks on the state. The lack of pricing transparency and open markets are detrimental to private sector investments and encourage monopolistic policies by state-owned entities. As governments around the world face budget shortfalls, there is pressure to reduce gas price regulations; nevertheless, the social impact of raising energy prices after decades of subsidies can be considerable and detrimental. 

Future of Gas and LNG Pricing

Predicting future gas prices is undoubtedly a fool’s game. Gas prices are set by supply and demand in only a limited number of places, including North America, the United Kingdom, and, increasingly, in Western Europe. In all other regions of the world, they are linked to oil prices, oil products, substitute energy, or regulated by government decree. The number and breadth of variables that impact gas prices are thus impossible to predict with any certainty. 

Over the past few years, there has been a steady increase in short-term and spot trades in LNG markets. Currently, over 30% of global LNG is sold on these terms with prices individually negotiated. Short-term prices are reported by agencies like Platts and Argus, and are increasing influencing perceptions of gas prices. 

Other trends which have become increasingly evident over the past few years include increasing volatility, increasing convergence between markets, continued growth of pricing hubs, increased LNG contract flexibility allowing increased trading opportunities, and continued delinking of gas prices to oil (and oil products) prices should be further analysed. 

In summary, global gas and LNG markets are undergoing structural changes. We have gone from a period of convergence in 2009–2010, to one of divergence during which oil prices were high, and back to a period of convergence since 2015, as shown in Figure 3. We can expect the next few years to hold more price volatility as innovative commercial models are tested and new players enter the market. However, the end results will be more transparency, higher impact of supply-and-demand forces, less linkages to unrelated commodity prices, and greater global price convergence. 

Exciting times are ahead!