Gas Pricing

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;

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 and the United Kingdom, the most liberal and traded gas markets in the world. Northwestern 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 Northwestern Europe 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, standardized contracts, increased infrastructure, government support, and general market liberalization. Remarkably, this transition has occurred despite the resistance of major gas suppliers, Russia and Norway in particular, who had benefited from the previous oil- and oil product–linked price regime. Undoubtedly, the rise in oil prices between 2008 and 2014 and the resulting rise in oil-linked gas prices demonstrated the benefits of delinking gas and oil prices to European consumers who were unhappy about paying significantly higher prices than their counterparts in the United Kingdom, where the National Balancing Point (NBP) hub price has been long established.

Group 1 regions are characterized by large numbers of buyers and sellers largely competing without governmental intervention. Gas is traded on open exchanges such as NYMEX, 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 Northwestern 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 maximizing usage of infrastructure and allowing both buyers and sellers to plan their financial future. Risks can be managed; however, short-term gas price tends to be volatile, continuously reacting to supply and demand.

An added advantage of a highly traded system is the spread of infrastructure over the entire network, not just at gas producing or consuming regions. A newly discovered gas field can be developed and marketed relatively easily, assuming that the pipeline grid is within a short distance, because there is confidence that produced gas can be sold at an established price. No prolonged gas marketing efforts are needed because the market has an established price-setting mechanism and all new gas volumes can usually be absorbed by the system without requiring that new purchase agreements be negotiated with individual buyers. 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.

Over the past decade, massive shale gas reserves have been developed in North America. Although Alaska (Kenai) has been a modest LNG exporter for many decades, the United States has only recently (in 2016) begun to export larger volumes of LNG to global markets. Pricing of US exported LNG is based on the US gas-on-gas pricing system, not based on a formula linked to oil prices. US upstream producers prefer to sell their gas using established gas-on-gas hub prices, and almost all US LNG export projects are structured independently of upstream production. LNG exports from the United States will have growing influence on global LNG markets where most long-term contracts continue to be linked to oil prices—with a fallout impact on non-LNG prices as well. 

The United States enjoys some of the lowest-cost conditions for gas production in the world, outside the Middle East and Russia. There is a large volume of gas in the United States that can be produced for less than $3.50/MMBtu, and because much of the gas is NGL-rich, it could actually be sold for much lower than this price depending on the relative price of NGLs, which can essentially subsidize gas prices. Labor, regulatory, and environmental costs are also lower in the United States, and efficient industrial infrastructure is present, allowing fast and predictable construction. Compared to many other countries, the United States has more stringent permitting procedures, and as a consequence, antidevelopment opposition groups have more opportunities to delay projects, thereby increasing permitting risk for new projects; however, this is offset by increased political stability and the advantage of having no nationalization risk. 

 

Group 2:

The second group of gas markets includes Central and Southern Europe, South Africa, and to a lesser extent, Southeast Asia. Whereas many countries in Northwestern Europe have rapidly evolved to gas-on-gas pricing with robust gas pricing hubs, much of Central and Southern Europe has yet to evolve toward group 1 characteristics. In group 2 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. Because oil prices—and, thus, oil product prices—have long been driven by oil market supply and demand, linking gas to oil products allowed gas buyers to derive gas prices from understood and more transparent benchmarks. 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.

The early European gas price formula contracts that linked gas price to displaced fuel were developed when the Groningen gas field in the Netherlands began production in 1962. Once a starting price was set, prices could fluctuate proportionally to changes in the price of substitute fuel, which in the case of Groningen, was coal. Gas producers in Norway, Algeria, and especially Russia encouraged this pricing scheme. They, as well as their government accountants, understood oil markets and thus could use the same concepts to negotiate gas sales contracts. 

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 fell, as they did in 2015–16, gas buyers, enjoying cheaper gas prices, largely muted their complaints and accepted the link even though the rationale for linking prices remained questionable. Nevertheless, much to the disappointment of large state-owned gas exporters such as Russia, Norway, and Qatar and major energy company partners such as Shell, Total, Chevron, ENI, and ExxonMobil, the trend toward delinking oil and gas is established and gaining converts—and there will be fewer gas markets that will be 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. 

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.

Group 3:

This group is largely characterized by the traditional LNG markets of North Asia—especially Japan, Korea, and Taiwan—and emerging LNG markets, such as India and China, 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. Thus, essentially all of their gas is delivered via LNG imports. China has significant domestic production and pipeline imports, but its growing LNG imported gas is largely priced on oil linkage on the model set by Japan and followed by Korea and Taiwan.

Before 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 convince them to substitute liquid and solid fuel for LNG sourced from potentially unstable 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 guarantee a minimum LNG price and to long-term contracts, thereby allowing their credit to be used by the project sponsor companies to fund the export projects.

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.

The following is a typical S-curve pricing formula: PLNG = (A × PCrude Oil)  + B, where PLNG is the price of exported LNG; A is the slope linking oil and gas prices (where 16.7% indicates energy equivalent parity between oil and gas prices; most LNG contracts have slopes between 12% and 15%); PCrude Oil is the crude oil price, which may be a weighted average of a basket of oils (e.g., JCC) or a single oil type such as Brent, and typically would be an average price over a defined period, usually of at least one month; and B is a constant added to reflect fixed costs, often related to shipping costs from LNG plant to importing port. This formula would usually also include kink points, the upper and lower limits where the slope flattens, thereby decreasing the impact that further oil price changes have on the LNG price. 

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.

The S-curve model has been followed by most of the pre-US LNG contracts to Japan, Korea, and Taiwan. This model did allow long-term contracts and financing arrangements facilitating multibillion dollar investments in LNG chain. It remains to be seen how the oil-linked S-curve pricing formula will survive the onslaught of US LNG into the region. The key driver for change would be the relative price of US domestic gas prices, which determine 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 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 Contracts

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

  1. 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.

  2. 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.

  3. 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