During the last two decades (2000-2019), the volume of the global LNG trade more than trebled, with overall share of LNG in natural gas trade increasing from 27.6 percent to over 49 percent during the same period (Figure S1.4).
From the demand side as well, LNG has been gaining traction as a reliable source of energy, due to a number of reasons:
First, technological advancements in power generation, particularly the advent of low-cost combined cycle generation turbine (CCGT) plants, have made it easier for oil-importing developing countries such as India, China and Turkey to switch to gas-fired power generation and take advantage of the cost flexibility.8 This has resulted in a continuous rise in the global production and consumption of natural gas (Figure S1.5). Given the expected surge in Chinese and Indian economies over the medium-to-long-term, traders and energy experts are expecting a similar surge in LNG imports to cater to the growing energy needs of their industrial, residential and power sector users.
Second, rising environmental concerns have been creating demand for cleaner fuel-sources such as LNG, since natural gas is free from sulfur, minimizes CO2 emissions, and is more efficient in generating electricity compared to other fossil fuels.
Third, the LNG value chain offers custom-made and small-scale solutions to cater to customers’ needs; these include small liquefaction and regasification plants and bunkering solutions etc. (Box S1.1).
Box S1.1: Understanding the LNG Value Chain
In contrast to the pipeline trade of natural gas, LNG trade requires substantial investments at multiple stages of value addition. The first stage in converting natural gas to LNG is the exploration of natural gas from underneath the earth’s surface. Countries with an exportable surplus of natural gas reserves export the commodity; exploration contributes approximately 11 percent to the overall cost of LNG. The next step is liquefaction, which involves the removal of various extraneous elements and ensures consistent composition and combustion characteristics of the natural gas. The liquefaction process requires huge investments and adds 42 percent to the overall LNG cost. Once natural gas is converted to liquid form (i.e., LNG), it is transported to the importing countries via specialized trucks and ships; for long distances, shipping is the preferred option. The overall transportation/shipping approximately adds 20 percent to the LNG cost borne by the importer. In the next stage of the value chain, the marine terminals at the importing destinations receive the LNG, store it, and later convert it back into gaseous form. In some countries, ships and barges – such as Floating Storage Units (FSUs), Floating Regasification Units (FRUs), and Floating Storage and Regasification Units (FSRUs) – perform these different functions. These floating facilities provide a rapid and low capital cost solution to the LNG importing countries, and approximately sum to 27 percent of the overall LNG landed price. In the last stage, the LNG in gaseous form is transported to the final customers through the countries’ own transmission and distribution networks.
Reference:
GIIGNL (2019). The LNG Process Chain. LNG Information Paper#2, October 2019 update. France: International Group of Liquefied Natural Gas Importers
As a result, the number of players in the global LNG supply chain rose manifold since the turn of the century. On the export front, new players such as Qatar, Australia, and recently the US, emerged and eventually surpassed traditional exporters such as Indonesia, Malaysia and Russia. Meanwhile on the imports front, China, India, and Pakistan generated sizable LNG demand in the international market. In response to mounting needs, the global LNG infrastructure underwent significant capacity expansions. From exploration to liquefaction, and shipping to regasification and distribution, all activities have seen a noticeable surge in investments.
For instance, the discovery of sizable shale gas reserves in the US had a market-altering impact on the global LNG trade, as the country transitioned from a net-importer to a net-exporter within the span of just a few years by investing heavily in export infrastructure. In the face of growing competition, Qatar has also recently planned to increase its LNG production-handling capacity by 64 percent by 2024, to make use of its recently discovered gas reserves.
Similar expansion plans have also been announced by other natural gas producing countries, including Canada, Mozambique and other West African countries.
Likewise, importing countries have been investing heavily to increase their LNG regasification, storage and pipeline capacities. For example, India, Bangladesh, China, and Brazil, activated new LNG regasification terminals in 2019. Meanwhile, new players are also embracing LNG imports; Philippines, El Salvador, Ghana, Cyprus, Croatia and Vietnam are in the process of setting up their first receiving terminals.
Recent policy transitions
An increasing shift to market-based LNG business
Initially, the governments or designated state regulatory bodies in both the exporting and importing countries were solely responsible for drafting the LNG trade agreements, and for building and maintaining the distribution and transmission infrastructure. In order to mitigate commercial risks, the contracts were drafted on a long-term basis, with fixed prices, pre-committed volumes based on a take-or-pay basis, and government guarantees. In such a model, exporters bore risks on the pricing front by locking in rates that, depending upon international dynamics, may end up being consistently lower than the prevailing spot prices. On the other hand, the buyers/importers accepted the risk on the volume front and, thus, had to ensure the development and operationalization of necessary infrastructure, and generation of enough demand to cater to the provisions made under the take-or-pay obligations. The importers under long-term contracts also assumed the risk of lower spot prices than the rates locked-in under their agreements.
With regards to regasification, transmission and distribution, the government of the importing country would often sign contracts with international oil companies (IOCs) and multilateral agencies to set up regasification units (both onshore or offshore), which were run by public sector enterprises.
However, after the installation and operationalization of the basic terminal and pipeline infrastructure by the governments of the LNG importing countries, there has been a growing trend toward deregulation and liberalization of the downstream LNG business in the wake of growing LNG demand. Japan and South Korea are major examples in this regard (Box S1.2). Their experience reveals that greater private sector involvement leads to better price discovery, based on the underlying market dynamics. Furthermore, it results in greater operational efficiency, as private players strive to grow in the absence of government-backed guarantees and notified or supported prices.
Multiple pricing options have emerged
In the relatively new LNG markets, the traders experience challenges with price discovery and unavailability of appropriate benchmarks. Furthermore, as mentioned above, most international contracts were state-executed, with governments treating important articles regarding pricing arrangements, ascribed volumes, and terms of pay-or-take provisions as highly confidential. Such complexities made the overall LNG pricing structure obscure and complex.
For instance, in Asia, due to the absence of a regional liquid trade market in the beginning, LNG prices were predominantly linked to crude oil under government-to- government agreements. However, as the market matured and the participation of private players increased, multiple alternative pricing options emerged (Table S1.1). For example, traders have started to use Gas-on-Gas prices, especially in big importing countries such as Japan and South Korea; China and India have also been increasingly transitioning towards market-based prices. This change materialized after the initiation of short and spot LNG trade between Asian and Atlantic economies, specifically after 2005.
Box S1.2: Liberalization in the Gas Market – The Case of Japan
In Asia, the three largest LNG importers - Japan, Korea and China - have all implemented multiple reforms in their domestic gas markets to deregulate retailing, increase competition and lower the cost of LNG.
Japan, for instance, had started the deregulation process in 1995, and had fully liberalized its retail market by 2017. Being the largest importer of natural gas and LNG, Japan meets around a quarter of its energy demand through LNG imports from Australia, USA, Qatar and Russia. The main consumers of natural gas in Japan are power supply companies and city gas, which distribute the fuel among industrial, commercial, and household sectors. Before the reform process in 1995, high fixed costs and economies of scale were the main reasons for the monopolistic nature of the retail gas market, with the government supporting the structure through tariff regulations and supply and safety obligations.
However, due to the growing demand from large-scale industrial users, the government introduced the first round of reforms in 1995, followed by subsequent rounds in 1999, 2004, 2007 and 2017. Under the reform process, the government had allowed non-traditional gas companies to sell gas in any area. Under the Gas Business Act 2015, the Japanese government abolished the regional monopoly in the retail market and allowed registered companies to enter the retail market. It also lifted the tariff regulations that were previously imposed on the retail companies. In addition, the government introduced a licensing system, where the companies were required to have licenses for gas manufacturing, pipeline service and gas retail business.
Furthermore, to encourage third parties’ access to LNG terminals, the terminal owners are prohibited to reject third-party use, and are required to report and publish their annual utilization plans. Besides, the government also introduced the legal unbundling of the pipelines’ service business and allowed new entrants to use the pipeline networks. This act necessitated the legal separation of the pipeline service business from the major gas companies by 2022, with the overall objective to promote retail competition in the pipeline network, as well as the import and terminal networks.
Reference:
IEA (2019). LNG Market Trends and their Implications: Structures, Drivers and Development of Major Asian Importers. France: International Energy Agency.
This is because such pricing had already been popular in the North American and European markets, including in Russia. In North America, for instance, the Gas on Gas (GOG) prices represented 100 percent volume of the natural gas market (this mainly represented pipeline gas contracts), whereas in other regions, like the former Soviet Union, a large number of natural gas contracts are based on the Regulation cost of services (RCS) and the Regulation below cost (RBC) models (Figure S1.6). As the Asian market developed, region-specific benchmarks also started gaining traction. These include the Japan-Korea Marker (also called the Asian spot index), and the newly- launched West India Marker (WIM).
The emergence of LNG portfolio players and spot market
In the LNG market, sellers seek long-term contracts to safeguard the interest of their investments, while buyers prefer short-term contracts to diversify supplies and avoid -volume commitments. Because of this, the role of portfolio players has become increasingly important in recent years. These players hold a portfolio of LNG supply, shipping, storage and regasification assets in different regions, and are therefore able to offer more flexible buying and selling options to exporters and importers. Portfolio players have become increasingly involved in the short-term and spot sales, and handle large volumes of “flexible gas supplies” (i.e. non-contracted and free to be supplied anywhere) purchased primarily from the US and Australia.
(To be continued)
(Excerpts from “The State of Pakistan’s Economy 2020-21: Second Quarterly Report of the Board of Directors of State Bank of Pakistan”)
Types of Wholesale Natural Gas Pricing Formation Mechanisms Table S1.1======================================================================================Mechanism Description Followed by======================================================================================Oil price The price is linked, usually through a base China; Japan;escalation price and an escalation clause, with S. Korea(OPE) competing fuels, typically crude oil, gas oil and/or fuel oil. In some cases, coal or electricity prices can also be used.--------------------------------------------------------------------------------------Gas-on-gas The price is determined by the interplay Russia;competition of supply and demand - gas-on-gas Europe;(GOG) competition - and is traded over a variety Colombia of different periods (daily, monthly, annually or other periods). Trading takes place at physical hubs (e.g., Henry Hub) or notional hubs (e.g., the National Balancing Point in the UK).--------------------------------------------------------------------------------------Bilateral The price is determined by bilateral Qatar; UAE;monopoly discussions and the agreements are reached Iraq(BIM) between a large seller and a large buyer, with the price being fixed for a period of time - typically one year. There may be a written contract in place, but often the arrangement is at the government or state-owned company level.--------------------------------------------------------------------------------------Netback The price received by the gas supplier is a Trinidad &from final function of the price received by the Tobagoproduct buyer for the final product the buyer produces. This may occur where the gas is used as a feedstock in chemical plants, and is the major variable cost in producing the product.--------------------------------------------------------------------------------------Regulation: The price is determined, or approved, China;cost of formally by a regulatory authority, or Bangladesh;service possibly a ministry, but the level is set Malaysia(RCS) to cover the "cost of service", including the recovery of investment and a reasonable rate of return.--------------------------------------------------------------------------------------Regulation: The price is set, on an irregular basis, Iran; Saudisocial and likely by a ministry, on a political/social Arabia;political basis, in response to the need to cover Oman(RSP) increasing costs, or possibly as a revenue raising exercise - a hybrid between RCS and RBC.--------------------------------------------------------------------------------------Regulation: The price is knowingly set below the average Egypt;below cost cost of producing and transporting Algeria;(RBC) the gas, often as a form of state Former subsidy to the population. Soviet Countries======================================================================================Source: IGU (2020). Wholesale Price Survey 2020. Barcelona: International Gas Union.