Thomas Vincent Borgersen
Feb 19 9 min
Traditionally, economies of scale led natural gas to predominantly be distributed through pipelines or shipped as LNG by massive carriers moored to expensive jetties, restricting the supply of LNG to locations of large demand. Due to developments in various fields such as transfer technology, climate policy, and pricing mechanisms, the demand for LNG is growing faster than pipeline gas, and increasingly reaching more dispersed and developing markets. Additionally, utilizing the Universal Transfer System (UTS©) enables LNG as a cleaner, cheaper, more efficient, and more flexible energy solution for developing markets and locations previously deemed unviable.
Natural gas, when cooled to -162 °C, changes its state to Liquefied Natural Gas (LNG), which also reduces its volume six hundred times, allowing LNG to be shipped economically over long distances. The world’s first ocean cargo of LNG occurred during January 1959, loaded onboard an LNG Carrier, Methane Pioneer, a vessel of approximately 5,000 DWT. The cargo was shipped from Louisiana, North America, and offloaded in Essex United Kingdom.
During the decades that followed, LNG markets developed regionally and in isolation due to the long distances between them. In the 1960s, two emerging regions were Asia-Pacific and the Atlantic Basin. However, having differing terms of pricing, project structures, and contractual requirements. The regional differences were, to some degree, evened out when Qatar started exporting LNG to these regions in the 1990s. In recent years, the distinction between regions has primarily vanished as a result of inter-regional trade agreements and an emerging spot market.
Today we mainly distinguish between three regions, Europe, Asia-Pacific, and North America. The three most prominent importers of LNG are Japan, China, and South Korea, making the Asia-Pacific region the largest LNG import market. China has increased their LNG imports massively over the recent years, further strengthening the region’s market position as a leading importer.
Point-to-point trade of Natural Gas through pipelines has traditionally been the primary delivery method in Europe. Moreover, LNG shipped to Europe needed to be competitive with the existing producers, the pipeline, and the gas distribution infrastructure.
The Asia-Pacific region had virtually no such pipeline infrastructure in place in the early 1990s, allowing the LNG market to grow rapidly as compared to the European market.
The competition continues within Europe between the LNG shipped from the US and the pipeline gas from Norway and Russia. European LNG imports increased by 148% from 2006-2016, covering over half of its annual gas demand. As a response to increased competition from LNG suppliers, Equinor of Norway and Gazprom of Russia instigated a pricing reform in order to become more competitive.
They forced prices down by using European spot prices instead of the traditional oil-indexed prices, which created a competitive situation, particularly over imported American shale gas. This provided the relatively cheap pipeline gas with an edge over the imported American shale gas that required additional liquefaction and shipping costs.
Figure 1: The three distinct trading regions of the present-day LNG-market – Asia-Pacific (East of Suez), Europe-Africa and the Americas – showing markets and trading routes.
North America, on the other hand, has, for the most part been self-sufficient, having Natural Gas transported through pipeline networks that connect Mexico, the USA, and Canada.
During a period of constrained LNG supply in the 1970s, several import terminals were constructed in the US to receive LNG from exporting countries such as Algeria. Additional LNG receiving terminals were built later in the 1990s when Natural Gas supply shortages were forecast due to rising demand.
During the mid 2000s, it became clear that the combination of factors such as vast shale gas reserves, disruptive innovations enabling shale gas exploration, positive government/industry sentiment and economies of extraction would allow the US to transition from an LNG importer to an exporter. Subsequently, several import terminals constructed during the 1990s, are now being converted into LNG export terminals.
Unlike crude oil, the pricing mechanism for natural gas has been established regionally and independently within each of the markets shown in Figure 1. Historically, the pricing of Natural Gas in Europe and Asia has been via negotiation and signing of long-term contracts between buyers and suppliers, with LNG price being influenced by the price of oil.
LNG projects have significant capital requirements through the entire value chain, and the stakeholders of natural gas fields require assurance of reliable and stable buyers before such projects can be fully financed.
For long term buyers of gas, a “take-or-pay” clause is often written into the Contract. The buyer agrees to “take” an amount of gas over a specific time frame. Should the buyer be unable to take the contracted quantity of gas, they are obligated to “pay” a predetermined penalty as agreed under the contract.
The “take or pay” mechanism can offer the buyer and supplier benefits in commercial risk mitigation since the buyer has a security of the gas supply over the term, and the supplier, receives a secure revenue stream.
When the LNG trade was first set in motion in Asia and Europe, power generation was heavily dependent on oil, especially in Japan. Consequently, the first LNG contracts were correlated to the price of oil, negating the risk of price competition. This was done by clever pricing formulas, where the price of LNG was correlated to the price of oil, however, only within a certain price range.
Figure 2: “The S-Curve”
Changing the correlation factor when the oil price was either very high or low, flattened the price-curve forming the appropriately named S-curve. Within the natural gas market, this has the effect of protecting the buyer during periods of very high oil prices as well as protecting the supplier during very low ones.
In 1992 the gas price was deregulated, and exchange-traded contracts were established. In North America, the pricing was based on commodity trade of futures contracts in a specific location. The historical reason for gas reference pricing came from a Liquid’s Wholesale Market in the US, where exchange-traded futures contracts enabled a transparent market-based price mechanism, which was not susceptible to the actions of a single trader.
Spot and future natural gas prices were set at the Henry Hub in Louisiana, being a distribution hub on the Natural Gas pipeline system and were generally seen to be the initial price set for the North American Natural Gas market. Today, LNG is increasingly being priced relative to emerging global reference prices, called “gas- on-gas” pricing, as it is related to relative supply and demand in the natural gas market.
Long term contracts and oil indexation still dominate in Asia and on continental Europe. The UK was deregulated in the 1990s, which led to the National Balancing Point (NBP) pricing, being a trading point for natural gas similar to the Henry Hub, only virtual. During the early 2010s, the Asia Pacific regions were first to start adopting Henry Hub-based LNG tolling contracts, as oil-indexation no longer made sense in this market. Currently, a new pricing index is being developed in the region that will cover long-term contracts for natural gas.
Due to the volatilities in the regional pricing of natural gas, suppliers and buyers are increasingly determined to develop pricing mechanisms that reflect the global value to support project development. The demand for LNG in Asia has not met the expectations, thus currently, there exists a temporary oversupply in this regional market, partly due to the US’ emergence as a net exporter.
In an oversupplied market, buyers have the bargaining power, resulting in increased flexibility in short-term volume and destination, and because of the price dramatically varying across regions, a spot and short-term market have emerged.
Short-term contracts are generally defined covering contracts spanning over less than four years. Spot contracts are generally defined as LNG for immediate delivery. Short Term & Spot prices allow LNG that is not allocated by a contract to be purchased by the highest bidder. Short-term and spot markets increased significantly after the Fukushima accident and required Japan to urgently import vast amounts of LNG as a consequence of the accident.
The spot market has by many been seen as the way forward to purchase high LNG volumes. The spot and short-term market grew from virtually zero before 1990 to 1% in 1990, 8% in 2002, 25% in 2011, and 31% in 2018. The Japanese spot price, “at its peak”, was double the local European and four times that of the local prices in the USA at its peak. Such price divergences lead Asian based LNG importers to look for better pricing structures.
Subsequently, the natural gas market that was initially dominated by government monopolies and OECD-countries was open for new and smaller players, such as independent power producers and traders that utilize arbitrage opportunities.
Given the global energy market’s volatile nature, countries with challenging economies are often reluctant to commit to collaborating on complex, expensive, and long lead time energy projects. In a global landscape with potentially new, disruptive or game-changing technologies emerging in the exploitation of natural gas, a buyer committing to long term contracts that can span over two decades may not consider that to be a viable option anymore.
From the developer and suppliers’ point of view, taking on long-term contracts with countries with financial and/or political challenges also represents a risk that may not be acceptable. The spot market can avoid such a dilemma to a large extent by enabling the commercially viable and secure trading of LNG between buyer & supplier.
During 2018, five countries in Asia, including India & Pakistan, imported 75% of the shipped global LNG supply. Utilizing the spot and short-term prices allowed these countries to access LNG quickly, at very competitive prices, and with lower commercial and supply risk.
Figure 2: Global Gas Spot Price Convergence on Worldwide Supply Gut
Developing countries with increasing energy demands and those aiming to phase out coal and heavy fuels are considering LNG, being a far cleaner alternative. Thus, the opportunities for small to medium-scale imports of have gained strong momentum as a commercially viable and environmentally beneficial alternative to dirty coal and heavy fuel oil projects.
LNG can be utilized for large-scale main-grid electrical power generation or in medium & small scale for cities and rural areas that are not connected to the domestic gas grid.
Developing countries with a desire to implement renewable power sources
such as solar and wind, often find the requirement for backup power overwhelming (i.e., what to do when the wind does not blow, and sunshine hours are low) when planning new power generating infrastructure. Hence, LNG will continue to play a significant role when it comes to producing secure and reliable baseload power requirements, also for renewable energy projects.
This particularly applies to countries lacking necessary infrastructure such as adequate roads and/or an incomplete electrical grid. An example is Myanmar, where major hydropower projects, with extensive grid expansions are being planned. Here, projects have continually been postponed due to financial, environmental, and political impediments. In Myanmar, LNG could enable expansion of an existing power generation grid, or microgrids could be built in isolated locations that could provide energy to rural areas where the population live outside the main grid and without clean and stable power.
One of the bottlenecks in the LNG value chain is the need to construct extensive marine facilities, plus the associated dredging needed to receive and safely offload LNG from a carrier. The cost of such specialized infrastructure for small or medium scale import facilities is likely to be commercially unviable for many locations. The added delays in obtaining approval from often numerous governing authorities controlling, land usage, construction, and environmental protection can add markedly to the complexity and time to completion of traditional fixed LNG receiving facility.
Jetty-less LNG receiving solutions are emerging into the spotlight and are already available and operational. The Jetty-less innovation is undoubtedly sparking new thinking as to how the import and export of LNG may be possible without the cost and inflexibility of traditional fixed-jetty infrastructure. This game-changer should open new opportunities within the LNG market as it will enable small, medium and large-scale shipments to be delivered into markets that up to now cannot afford the massive cost of fixed jetty infrastructure.
The Universal Transfer System (UTS©) by Connect LNG is one jetty-less solution providing turn-key operation for the import, export, bunkering or reloading of LNG. The UTS floating jetty-less system has the potential to bring many projects to fruition that have up to recently thought to be economically unviable.
“Commodity tracker: 6 charts to watch this week”, S&P Global Platts. Available online at: https://blogs.platts.com/2019/09/09/commodity-tracker-6-charts- 090919/