By Energy Worth
Liquefied natural gas (LNG) has become one of the most widely traded energy commodities in the world. Yet the way its price is determined can seem complex to many observers. Unlike crude oil, which is largely priced using a few widely recognised global benchmarks, LNG pricing is influenced by a combination of long-term contracts, market indexes and shipping economics. These factors reflect both regional demand and the cost of producing and delivering the fuel.
At its core, LNG pricing is shaped by three main components: the cost of gas supply, the cost of liquefaction and transportation, and the market index used in the sales contract. Traditionally, LNG has been sold through long-term agreements that often last between 15 and 25 years. These contracts are designed to guarantee steady revenue for producers while ensuring reliable supply for importing countries.
Such long-term arrangements have been crucial in financing large liquefaction plants, which can cost tens of billions of dollars to build. Major international energy companies such as Shell Plc, TotalEnergies and Chevron Corporation have developed several of these projects around the world.
For many years, most LNG contracts were linked to crude oil prices. The reasoning was straightforward. In Asia—the earliest and largest LNG market—natural gas historically competed with oil products for power generation. As a result, LNG prices were tied to oil benchmarks using a formula that links gas prices to a percentage of crude oil prices.
A simplified version of the formula is often expressed as:
**LNG price = α × crude oil price + β**
In this formula, the factor known as the “slope” (α) represents the proportion of the oil price used in determining the LNG price.
In practice, the slope negotiated in LNG contracts typically ranges between about 11 and 15 percent of the oil price per barrel. For instance, if crude oil trades at $80 per barrel and the slope in the contract is 12.7 percent, the resulting LNG price would be roughly $10 per million British thermal units (MMBtu).
Over the past two decades, however, the LNG market has evolved significantly. Spot trading—the buying and selling of cargoes for near-term delivery—has grown rapidly. As a result, LNG pricing is increasingly linked to regional gas benchmarks rather than oil alone.
One of the most influential benchmarks today is the Japan Korea Marker (JKM). This index reflects the spot price of LNG delivered to key Asian markets such as Japan, South Korea, China and Taiwan. The JKM benchmark is widely used to price short-term LNG cargoes and is increasingly referenced in newer long-term supply agreements.
Under this system, LNG prices are often calculated based on the average JKM price over a given month. Buyers and sellers may then negotiate a premium or discount depending on factors such as shipping distance, contract duration and delivery conditions.
According to the World Bank’s handbook on natural gas markets, about 70 percent of global LNG trade historically relied on oil-linked pricing formulas. However, hybrid models that combine oil and gas benchmarks—as well as hub-based pricing—are becoming more common as the LNG
market becomes more liquid and flexible.
Large international LNG projects provide practical examples of how these pricing mechanisms work. Australia’s Prelude FLNG facility, operated by Shell plc, produces around 3.6 million tonnes of LNG annually from offshore gas fields. The facility sells cargoes into global markets through a mix of long-term contracts and spot transactions.
Similarly, the Mozambique LNG project led by TotalEnergies is expected to export about 13 million tonnes of LNG per year when fully operational. Much of the output is aimed at high-demand Asian markets where contracts are still frequently linked to oil prices or regional gas benchmarks.
In Australia, Chevron Corporation is a key partner in the Gorgon LNG Project, one of the world’s largest LNG developments with a combined capacity of about 15.6 million tonnes per year. Cargoes from projects like Gorgon are typically sold under long-term supply agreements that incorporate either oil-linked or hub-indexed pricing formulas.
Industry analysts say the increasing diversity of LNG pricing models reflects the growing globalisation of gas markets. According to energy consulting firm Knowledge Ridge, the LNG market has gradually shifted from rigid oil-linked contracts to a more flexible mix of oil, hub and spot indexation. Modern LNG deals, analysts say, often combine commodity benchmarks with logistics costs such as shipping and regasification.
Shipping economics also play an important role in determining the final LNG price. Because LNG cargoes are traded globally, traders often send shipments to whichever region offers the highest netback price after transport costs are deducted. For example, if spot prices in Asia rise above European gas benchmarks, cargoes may be redirected to Asian buyers.
Ultimately, LNG pricing is best understood as a hybrid system shaped by long-term contracts, evolving market benchmarks and global supply-and-demand dynamics. As new liquefaction capacity is added around the world and spot trading continues to expand, analysts expect LNG markets to increasingly resemble oil markets, with clearer benchmarks and stronger price competition.
For producing countries and investors alike, understanding how LNG pricing works is essential. Multi-billion-dollar projects—from Australia to Mozambique—depend on these pricing structures to secure financing, guarantee revenue streams and determine whether the world’s fastest-growing fossil fuel market remains profitable in the decades ahead.
Sources: Reuters, S&P Global, and the World Bank’s PPP Resources Center.
