The basis on which natural gas is sold and priced varies dramatically between global markets. As natural gas becomes an increasingly important source of energy, understanding of gas pricing concepts is crucial for energy producers, consumers, and regulators.
Though natural gas and oil share many characteristics (both are hydrocarbons, both are found and produced using similar methods and equipment, and both are often produced simultaneously) they contrast in the way they are sold and priced.
Oil is sold by volume or weight, typically barrels or tons. By contrast, natural gas is sold by unit of energy. Common energy units include British Thermal Units (Btu), Therms, and Joules (J). Natural gas, when produced from the reservoir, contains majority methane plus various other hydrocarbons and, undesirably, some impurities. Natural gas liquids (NGLs), a term that includes ethane, propane, butane, and condensates, are composed of longer chains of carbon molecules than methane, and thus, per unit volume, they burn hotter than methane. Because they burn hotter, NGLs have a higher energy content than methane and even small quantities of NGLs in a natural gas flow can have a large impact on the overall energy contained in the natural gas. By contrast, impurities such as carbon dioxide, hydrogen sulphide and nitrogen are largely non-combustible. The presence of these compounds has the overall effect of reducing the energy content of the natural gas flow.
If sufficient quantities of NGLs exist in the natural gas, it is often more economic for the field operator to remove the NGLs from the natural gas flow for direct sale. NGLs are desired by global markets to produce various petrochemical products, to be blended with crude oil to make more valuable products, and can also be combusted directly. Readers would be familiar with using Liquefied Petroleum Gas (LPGs), which is a subsector of NGL containing propane and butane, for domestic cooking gas as well as transport fuel in many countries. NGLs prices tend to track crude oil prices and thus are much more valuable sold separately than sold with the majority methane natural gas flow. Removing NGLs requires relatively sophisticated gas processing units which may not be economic to construct if the particular natural gas flow does not contain sufficient quantities of the more valuable NGLs. Since NGLs are easier to transport than methane (which requires either a pipeline, or expensive compression or liquefaction transformation), NGL prices are more influenced by global prices. If NGL relative volumes are low, they are usually left in the natural gas stream and sold at gas prices.
A large majority of crude oil is bought and sold directly or indirectly through highly liquid global markets. Quoted oil prices usually refer to a specific type of crude oil (with unique characteristics) at a specific delivery location. For example, in the United States, crude oil price usually refers West Texas Intermediate, a specific type of oil, sold at a defined location in Oklahoma. Any oil traded in the United States would ‘benchmarked’ against this value, and be sold at a premium or discount to this benchmark price.
In contrast, because natural gas is difficult to transport, natural gas prices tend to be set locally or regionally. The large majority (over 90%) of traded natural gas is transported by pipeline. A pipeline may connect a single producer with a single buyer of gas – such as a case of a gas field supplying to a dedicated power plant – or may consist of a sophisticated grid connecting thousands of individual gas producers and thousands (or even – in the case of a urban grid - millions of gas consumers). Natural gas prices in the first case, involving a single producer and single buyer, would be negotiated between the parties. The seller would require a price that covers his capital and operating costs, as well as compensate him for the risks that he took to discover the gas field, plus a sufficient profit to please his shareholders. The buyer (electricity generator) would agree to pay a price that allows him to earn a sufficient margin (ie: differential between the price he receives for the generate electricity and the total costs of generation, including capital and operating costs, plus his gas fuel costs) that give him a sufficient profit to please his shareholders. The price of other fuels, such as diesel or coal, would also factor into his decision to buy gas from the producer – however, if the electricity generator does not have the ability to substitute gas for these other fuels, the influence of diesel or coal prices may be limited.
In the second case, where there are many buyers and sellers of gas, traded prices are most influenced by supply and demand. If the weather is cold, and most of the gas is used for space heating, gas prices may rise in the winter months. If most of the gas is used to generate power mainly used for air conditioning, gas demand would rise in the hotter summer months. If gas is used, either directly or indirectly, by industrial consumers, influence of weather would have a minimal impact on gas demand. Disruptions in gas supply (due to offshore hurricanes in the US Gulf of Mexico, for instance) would limit supplies and thus increase prices.
Most gas markets in the world are between the two extremes as described above. The graphic below divides the world gas markets into four groupings;
This group, which includes North America and UK, are the most liberal and liquid gas markets. The regions are characterised by large numbers of buyer and sellers largely competing without governmental intervention. There are well established quoted benchmark prices – in the United States this is the Henry Hub price which is a theoretical price of gas in Louisiana and in the UK it the NBP price at a defined point in the gas grid – set by transparent markets such as New York Mercantile Exchange (NYMEX). Because gas prices are set in relation to gas supply and demand, this system is also referred to as ‘gas-on-gas’ markets.
Because North America, and to a lesser extent, UK, have an extensive pipeline and gas storage system, with opportunities to both export and import gas from outside the markets, gas can be traded on both current and future contracts. It is possible for a buyer to buy a certain volume of gas, to be delivered at a certain point on the gas grid, at a date five years the future, at a known price today. This sophistication allows the market to be very efficient by maximizing usage of infrastructure and allowing both buyers and sellers to plan their financial future. Risks can be managed but the gas price tends to be volatile, continuously reacting to supply and demand sentiments.
An added advantage of a highly liquid system is the spread of infrastructure over the entire country. A new gas field can be developed and marketed relatively quickly, assuming that the pipeline grid is within a short distance. No long gas marketing efforts are required because the market sets the price, and all new gas volumes can usually be absorbed by the system without the requirements to negotiate long-term purchase agreements. 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.
The second group of gas markets includes the situation in continental Europe, and to a lessor extent, in south-east Asia. In these regions, there is a limited, but growing, gas grid. There are some gas storage facilities, and developing gas market. However, most gas is priced in relation to other fuels, usually crude oil or oil products. Thus, gas prices would be quoted by a formula which ‘indexes’ or is derived from oil prices. The net effect is that gas is usually, though not always, sold at a discount – on an equivalent energy basis – to oil and oil products. The reasons for this are largely historical – gas production and consumption began after oil markets were established and by linking the markets, gas producers could convince producers to switch between the fuels – and also because oil markets are global and transparent, gas prices could be derived from traded oil-price financial instruments. When oil prices rise, oil-linked gas prices would also rise, and vice-versa.
Gas producers in Norway, Algeria, and especially, Russia, encouraged this pricing scheme. They, and their government treasuries, understood oil markets and thus could use the same concepts to negotiate gas sales contracts. During the period when oil and gas prices in the US largely tracked each other, on an energy equivalent basis, this system suited both buyers and sellers. However, once oil prices began to rise in 2008, the spread between oil and gas prices has widened dramatically. For example, when oil prices are $120/ bbl, the theoretical energy equivalent gas price should be $20/MMbtu. Gas prices have been a quarter of that level for the past few years. This discrepancy is encouraging buyers of oil-linked gas contracts to question the value of linking the price of the commodities. During the same period, Europe witnessed the construction of many LNG import facilities operated by aggressive trading or utility companies motivated to source cheaper (and at prices not linked to oil prices) LNG volumes, displacing the comparatively expensive pipeline gas for the traditional suppliers (Norway, North Africa,and Russia) who have been reluctant to drop their oil price linkage.
As the number of buyers and sellers of gas in these markets increase, the link to oil prices will weaken and, in time, this markets in this group will begin to resemble the more liberal and open ‘gas-on-gas’ markets of Group 1.
This group is characterised by the traditional LNG markets of north Asia, especially Japan. Japan has very limited energy resources and does not have the ability to import gas by pipeline. Almost all of Japan’s gas is delivered to the islands via LNG. The LNG was initially sourced from Alaska and south-east Asia but current suppliers also include the Middle East and Australia.
Prior to the introduction of LNG, Japanese power utilities relied on imported crude oil and coal for their power generation. Similar to the European experience, these risk-averse buyers insisted on a guaranteed discount to convince 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 prices are linked to oil and guaranteed a discount at all oil prices. They also wanted a ceiling concept to be introduced to that future oil shocks would not translate into higher gas prices.
The solution was the innovative ‘S’ curve concept as shown in the diagram below:
The horizontal axis is the weighted average of Japan crude oil import price, known as the Japan Crude Cocktail (JCC) price. This protected Japan against regional crude oil price shocks since Japan imports oil from Middle East, south-east Asia, South America, and Africa. The vertical axis is the imported LNG price.
The middle section of the line is the range where changes in the JCC have a direct impact on LNG prices. The slope of the line determines the relationship between the two prices. If the slope is 16.7%, LNG prices are equal, on an energy equivalent basis, to crude oil. Slopes less than 16.7% imply that LNG is sold at a discount to oil, and slopes greater than 16.7%, though rare, imply that LNG will sell at a premium price to oil.
In the 1970s to 2000 period, the slope was in the 14% range, implying a large LNG price discount. As the markets tightened in the period between 2006 and 2008, the slope increased to 16% and in some cases, exceed the 16.7% threshold. The slope for new LNG contracts signed in 2011 is in the 15% range.
The lower slope sections below and above the ‘kink points’ in the line are the ‘S’ curve legs. If these sections are horizontal, they would be ‘floor ‘and ‘ceiling’ prices where the LNG prices are flat and no longer linked to oil prices. The floor prices protect the LNG seller – the seller is guaranteed a certain minimum price irrespective if the oil prices drop below the kink-point. The ceiling price, on the other hand, protects the LNG buyer, who is guaranteed a maximum price for the LNG, even if oil prices rise over the defined kink-point. The ‘S’ curve model has been followed by most of the LNG contracts to Japan, Korea and Taiwan. This model allowed long-term contracts and financing arrangements that facilitated multi-billion dollar investments in LNG chain.
Emerging buyers of LNG, such as China and India, are resisting the explicit link to oil prices as they see a future period of high oil price and relatively low gas prices – thus they see no benefit in linking the cheaper gas to more expensive oil. LNG is used by gas combusting power generators who do not have the ability to burn oil as a substitute for gas making the link harder to justify.
The Japanese market is characterized by a handful of LNG buyers, each who operate a local pipeline grid radiating from their own LNG receiving terminals. There is no real national pipeline grid in Japan and it is relatively difficult to trade gas from one company’s system to another. The consequence of this is that there is no national gas market and high inefficiencies in the system. The few gas trading companies are relegated to trading LNG cargoes, not actual pipeline gas deliveries.
The situation in Korea and Taiwan is even more dominated by the market leaders. In both markets, one company effectively controls the entire the pipeline grid and buys a majority of the LNG cargoes imported by the country.
If the current dynamic of high oil prices and low gas prices (in markets such as the US) continue, LNG importers in north Asia may demand a weakening of the link to oil prices. However, since the utilities are effectively all state controlled and have the ability to pass increased costs to their customers, it is unlikely that this driver will result in a rapid change in the status-quo.
Regulated markets dominate much of the other regions of the world. In these regions, the gas markets are relatively immature and largely controlled by the State. The gas prices may be nationally set (by decree in many cases) and all supply in entered into a gas ‘pool’. The state manages the differences in supply prices, and may chose to sell gas at prices less than the average ‘pool’ price for political reasons. There is no transparency in prices, no markets, and very little incentive – unless they receive special licence from the government – for private sector investment in supply or infrastructure. If the mandated gas prices are artificially low, such as in the Middle East, inefficient consumption of energy often occurs.
In the future, natural gas pricing around the world will continue to be divergent and unlinked between markets. As the LNG industry grows and links more and more markets, there may be some convergence at the margins – however, since a large majority of gas will continue to be transported by pipeline, the overall impact of this will be limited. The link to oil price has worked for many decades - to the benefit of entrenched LNG suppliers. However, with the growth of US LNG exports and the realization by LNG customers that there are alternatives to artificial and increasingly irrelevant oil price links, expect to see many future LNG contracts with hybrid or completely delinked prices. This will benefit markets and also suppliers who are willing to be transparent in their pricing.
A good article (published in Sept 2014) about the trends can be found here.
Gas Sales and Transportation Contracts
The volume of gas available for sale by the oil and gas company is a function of the volume of gas produced and the fiscal terms in place. Cost of production, taxes, government controls, or market forces set by local or regional supply and demand often determine the price of gas sold.
Gas prices that the producing company actually realizes are a function of:
→ Market price of gas, determined by supply, demand, and price of substitute fuels, such as coal or oil
→ Terms of the sales contracts
→ The relative distance of the customer to the producing field
→ Terms of the transportation agreements
→ Host government fiscal terms
The technical and financial status of both the consuming and producing companies
Transmission tariffs may be based on distance transmitted or on a postage-stamp basis, where all consumers pay the same tariffs regardless of distance transmitted, similar to a domestic mail postage rate. Tariffs may also be a function of the volume reserved for a particular buyer (a set capacity charge) and a variable based on the pipeline volume actually consumed by the buyer (a commodity charge). As mentioned previously, gas is sold by unit of energy, not by volume. Prices are usually stated in price per unit of energy, such as dollars per million British thermal units, rather than price per unit volume, such as dollars per thousand cubic feet. Transportation tariffs, on the other hand, are often priced per unit volume, not per unit energy. This can be a source of confusion and mistakes if not correctly handled.
Gas sales agreements
The pipeline gas sales agreement (GSA) is also known as a gas purchase agreement (GPA) or a gas sales and purchase agreement (GSPA). These agreements between a producing company or sales agent (seller) and a consuming company (buyer) usually cover a number of provisions.
→ Term. The term of a GSA can be as short as one day or as long as the economic life of the field from which the gas is produced. Internationally, especially where a gas development project will have a limited number of potential customers, the terms could reach 20 or 30 years.
→ Quantity. Broadly speaking, there are two distinct types of volume commitments contracts: depletion contracts and the more common supply contracts. Under depletion contracts, also called output contracts, the producing company dedicates the entire production from a particular field or reserve to a buyer. In contrast, supply contracts commit the seller to supply a fixed volume of gas to the buyer for fixed term, typically 20 to 25 years. The seller is responsible for sourcing the gas, either from its own reserves or from third parties, if its own reserves are inadequate to fulfill the obligations.
→ Price terms. Gas must be priced at a level competitive with alternate fuels in the marketplace and provide an adequate return for all parties in the chain. Pricing may be fixed, fixed with escalators, or floating. A fixed price is a set negotiated price over the term of the contract and is usually found in shorter-term contracts. A fixed price with an escalator is a fixed price that changes by a certain percentage every year or other specified time frame to reflect an inflator or an index of a known variable. Indexing prices helps to ensure gas price competitiveness to alternate fuels and helps to integrate changes in the marketplace without renegotiating long-term contracts. Most gas contracts in Europe are indexed to the price of crude oil or other liquid fuel products imported by the gas buying country. Alternatively, a floating price varies according to prices reported by unbiased sources, such as newspapers and NYMEX quotations. In this case, the contracts are revalued every month or every week according to the reported prices. Prices, both fixed and floating, may also be limited to a maximum ceiling price or a minimum floor price for the term of the contract. Contracts may also have combinations of fixed and floating prices.
→ Delivery obligation. The terms of delivery may be firm or flexible. Firm delivery implies an obligation by the producing company or seller to deliver the specified quantities over the term of the contract. If the delivery obligation is not fulfilled, the seller may be obliged to pay damages or cover the costs of alternate fuels used by the buyer. Flexible delivery obligates the producing company to make attempts to fulfill the delivery obligation but does not require fulfillment of all the delivery obligations.
→ Take-or-pay (TOP) obligations. The basic premise of take-or-pay (TOP) is that the buyer is obliged to pay for a percentage of the contracted quantity. This is true even if the buyer is unable or fails to take the gas supplied by the seller, other than due to fault of the seller or force majeure incidents. The seller usually imposes this obligation on the buyer to guarantee a predictable minimum cash flow, and financial institutions involved in the gas field or pipeline development may require these obligations as a condition for financing.
→ Delivery point. This is the physical location where gas is delivered to the buyer. It could be at the gate of the power plant, the hub for a city grid, an interconnection of two pipeline systems, the site of a compressor, international border, or the fence of an LNG plant. This is often, but not always, the same geographic point where custody transfer—transfer of ownership and responsibility-of the gas takes place.
→ Gas quality. The GSA clearly states the quality of gas, including its maximum and minimum heating values (in Btu/MMcf units); maximum level of impurities like oxygen, CO2, SOx, and NOx; the delivery pressure; and water vapor content. If the seller delivers off-specification gas, buyers may be able to demand a discount, a reduction in TOP obligations for the period, or other remedies as specified in the GSA.
LNG sales and purchase agreements
Because of the large capital expenditures, the international nature of the business, and number of discrete elements in the value chain, the LNG business requires numerous legal agreements. The LNG SPA shares many of the features of the pipeline-delivered GSA described previously, but the LNG SPA includes additional unique features.
→ Buyer. Typically, Pacific region LNG buyers are large, government-supported, creditworthy gas or power utilities. However, today, many LNG buyers are no longer exclusively large monopoly utilities. Deregulation has created a host of smaller energy suppliers, many of whom are willing to sign LNG contracts and have access to receiving and storage facilities.
→ Price. When companies negotiated the first generation of SPAs, many of the power plants operated by Japanese utilities were able to use either oil or natural gas to generate electricity, so the price of LNG was linked to the price of oil. Today, prices are often tied to market gas prices, especially in North America and Europe. LNG exporters are forced to accept fluctuating prices linked to market gas prices in the buying country, with or without floor and ceiling prices.
→ Shipping terms. Deliveries may be on
- Free-on-board (FOB) basis, where the buyer takes ownership of LNG as it is loaded on ships at the export LNG facility. The buyer is responsible for LNG delivery, either on its own ships or ships chartered by the buyer. The contracted sales price does not include transportation costs.
- Cost-insurance-freight (CIF) basis, where the buyer takes legal ownership of the LNG at some point during the voyage from the loading port to the receiving port. The seller is responsible for the LNG delivery, and the contracted sales price includes insurance and transportation costs.
- Delivered ex-ship (DES) basis, where the buyer takes ownership of the LNG at the receiving port. The seller is responsible for LNG delivery, and the contracted sales price includes insurance and transportation costs.
→ Transfer of title. Under CIF contract, transfer of title or ownership of the LNG cargo, and associated risks, can legally occur at the regas facility, the international marine boundary, or any other mutually agreeable point on the ship voyage. DES contracts usually involve transfer of title at the unloading berth at the regas facility. By contrast, FOB contracts always transfer title and risk at the loading terminal of the liquefaction facility.
Please watch the video below to hear the author explain these concepts in detail. The video is the sixth module of Natural Gas Dynamics , an online natural gas / LNG course developed by the author