International Gas Trade-International Pipeline Trade
International Gas Trade
The global gas trade is the fastest growing segment of primary energy, with the exception of renewable energy which is growing from a much lower base production. The gas trade is expected to continue to increase by more than 2 - 3% per year for the next twenty years. Much of this will be within the borders of countries; however, an increasing amount will involve crossing international borders by pipelines and LNG, and will involve emerging economies such as China, India, SE Asia, and Latin America.
International Pipeline Trade
As the global demand for gas increases and local supply options decline, the requirement to import gas via pipelines that cross international borders increases. Crossing international borders raises the complexity and risks of pipeline investment. It has been stated that every international border crossed raises the complexity of a project by an order of magnitude - this explains why pipelines, with the notable exception of Eastern Europe to Western Europe, are largely confined to domestic or single-border crossings. Crossborder pipelines amplify commercial risks, especially when third-party countries that are neither sellers nor final buyers of the gas are involved. These transit countries demand fees or other concessions - such as cheap or free gas - from producers or consumers, or both, in exchange for allowing pipelines to cross their territories.
The scale of international pipeline projects, both completed and planned, is staggering, with the majority of future pipelines connecting central Asia to markets in Europe and Asia. Pipelines to export Iranian gas are mired in internal politics, while pipeline projects to connect South East Asia will like be superseded by regional LNG trade. North America is poised to become a surprising player in future gas pipeline construction as shale gas production becomes abundant and economics of selling gas to regional and international markets become compelling. As one would expect, the price of steel and construction may make many of these projects commercially and technically challenging.
Liquefied Natural Gas (LNG) Trade
Worldwide trade in LNG has steadily increased since the first delivery of LNG from the United States to the United Kingdom in 1959. In 1964, Algeria became the site of the first commercial LNG plant, initially exporting its product to the United Kingdom. LNG is the most exciting and fastest growing of all the fossil industry trades, and is poised to continue to attract more companies and countries in the decades to come. Total LNG trade has increased nearly 5 times from the 1990 level, to ~250 million tonnes today.
The number of LNG producing countries steadily continues to grow, from 8 in 1996 to 15 at the beginning of 2008 and ~30 by 2020. The number of consuming countries is also growing, currently over 25 countries have terminals, encouraging the LNG trade to become more competitive and market driven. A recent IEA estimate calculates more than $250 billion of new investment, in all parts of the LNG chain, will be required to meet demand until 2030.
Two distinct LNG trade regions have developed over the past few decades; the Atlantic Basin and the Pacific Basin. Until Qatar, and to a lesser extent, Oman, began to export LNG to both regions in the mid-1990s, the two regions were largely separate, with unique suppliers, pricing arrangements, project structures, and terms. There were occasional spot sales with suppliers from the Pacific Basin selling to the Atlantic Basin customers. However, long-term contracts between the regions began with Qatar and Oman selling to Europe and North America. Qatar, playing the role of swing producer, has 77 MTA (out of around 250 MTA worldwide capacity) and, with its favourable location, can play the role of the swing producer exporting to both the Atlantic and Pacific Basins. Cargoes are now routinely sold and transferred between the regions.
The 2011 earthquake and tsunami events in Japan demonstrated that the global LNG market is robust enough to handle unexpected disruptions - in this case, a surge in LNG demand in Japan as it struggled to maintain its power production in the wake of the nuclear shutdown - without any major shortages or price spikes. It may have been fortunate that the crisis occurred as Spain and other European buyers were experiencing economic slowdown and the US domestic gas production was surging, thereby freeing up Atlantic cargoes for Japan. The experience has undoubtedly convinced buyers that the global LNG trade is now mature enough to handle disruptions, and the belief that LNG supply security should be more important that competitive price is now looking increasing weak.
The growth of spot and short-term trade, along with new trading and 'aggregator' entrants into the trade will hasten the evolution of the LNG industry into a more 'traditional' commodity, with competitive prices, shorter term contracts, and arbitrage across markets. This trend is being resisted by many LNG producers, especially the higher cost future producers such as the multitude Australian projects with projects under construction.
The growth of US shale gas will have very significant impact on the global gas markets. The prospect of relatively cheap LNG (especially if US gas prices stay low) priced on a 'gas-on-gas' basis (instead of the traditional oil-linked prices) at very large volumes (the US could easily export over 50 MTA by 2020) will be disruptive to the LNG trade. It is hard to estimate when the impact will cause a shift in the mindset in Asia Pacific, but in this uncertain environment, buyers may want to avoid long-term oil-linked priced deals - and sellers may want to sign these type of agreements as soon as possible!
LNG Markets
Pacific Basin
For many decades, the Pacific Basin was the centre of LNG innovation and activity. The Pacific trade, previously accounting for more than 70% of worldwide trade but now lower due to increased LNG imports to Europe, includes exports to Asian consumers from Asia, Western Latin America (Peru), Middle East and, in the future, East Africa. The convergence of the Atlantic and Pacific markets has grown due to the efforts of producers such as Qatar who are able to arbitrage across both markets. Once North American and East African project begin to export LNG, this trend will accelerate as these new entrants would be able to supply both markets as well.
Main buyers in the Pacific region are Japan, South Korea, Taiwan (the 'JKT' buyers), and emerging buyers such as China, India, Thailand, Indonesia and, in late 2013 Singapore. Both Singapore and Thailand are aiming to become LNG hubs that will allow cargoes to be offloaded, stored and resold when the prices are favourable. Singapore, in particular, is encouraging LNG trading companies to relocate to the island-state by granting favourable taxation. Japan's dependence on LNG has grown after the 2011 disasters and there are signs that Japanese buyers are beginning to be less conservative and willing to emulate buyers such as Korea's KOGAS, which has become the world's largest buyer of LNG by taking large interests in projects and, in some cases, technical (ie: FLNG and Unconventional) and exploration risks.
Atlantic Basin
The Atlantic LNG trade has developed differently than the Pacific trade. Until last decade, the regions were completely separated, with no common LNG suppliers. The regions have begun to converge as Qatar, and to a lesser extent, Oman, have begun to supply both markets. The growth of the spot and short-term markets has also encouraged markets to cooperate. However, there remains large price disparity between the markets which will likely continue until new large scale suppliers (such as the US) disrupt both markets with new pricing schemes and flexible supply.
The Atlantic basin is dominated by key European markets; UK, Spain, Italy, France and Belgium / Holland. LNG has been imported into Continental Europe since the mid 1970s, when France signed an agreement with Algeria. In the past few years, a majority of European countries with sea ports have built LNG terminals.
European pipeline trade from Russian and CIS is largely influenced by the German market; likewise the North African pipeline trade is under the control of French, Italian and Spanish interest. Gas from Norway is sold to both continental and UK markets.
The US import market was expected to be a significant LNG player - however, with the incredible growth of shale gas production since 2005, the US share of the world wide LNG trade is minimal - though the US continues to import large volumes of Canadian gas via pipelines. The likely prospect of North American LNG exports around 2016 onwards will, however, disrupt the global LNG trade and potentially cripple the LNG pricing formulas (sustainability of oil-price linkages ) and contract terms familiar with buyers today. If the US experience of shale gas is repeated in other regions, an unlikely prospect due to a variety of reasons, the global gas markets could be altered radically.
Gas Exploration
Gas Exploration
The exploration processes for oil and gas are the same. Both oil and gas reservoirs are buried deep underground, at depths of a few hundred meters to many thousands of meters. In addition, these reservoirs are often found under the sea. Interestingly, other than the obvious usage of boats versus land surface vehicles and the presence of surface features, there is relatively little difference between exploration on land or water. Recent advances in exploration and production methods have allowed production of reservoirs located thousands of meters below the seabed, which itself could be thousands of meters below the surface of the sea.
The study of geophysics uses physical properties measured either on the surface or inside wells to determine the property and structure of rocks below the surface. Geophysics has dramatically changed the way reservoirs are discovered. The first geophysical methods were simple gravity and magnetic surveys on the surface, progressing to subsurface measurements of seismic energy waves, radioactivity, and sonic properties.
Gravity surveys measure the slight variations in gravity readings to locate subsurface rocks of different densities. Magnetic surveys measure the changes in the magnetic field over an area to locate sedimentary rocks, which have a lower magnetic field than igneous and metamorphic rocks. Mapping the variations in gravity and magnetic readings over a large area produces subsurface maps showing the lateral extent of potential reservoir rocks. By drilling at the high point of the sedimentary rock formations, exploration professionals (“explorationists”) hoped to locate the peak of the anticlinal trap and find a hydrocarbon reservoir.
The development of seismic technology may be the most profound development in the hydrocarbon industry since the discovery of the first oil wells. Explosives, air guns, or vibrating pads directly on the surface generate low-frequency energy waves, which reflect and refract as they pass through the different rock layers. The figure below shows a simplified schematic of this process. The speed at which the waves travel is related to the density of the individual rock layers. Each rock layer has its own density, which determines the time it takes for the waves to pass through the layer (refracted into the next deeper layer) or to be reflected back to the surface. Sensitive microphones (known as geophones on land and hydrophones on the surface of the sea) record the time taken for the waves to return to the surface after they have been refracted and reflected in the earth. These sensors are similar to seismographs used to measure naturally occurring earthquakes.
For a single seismic source, hundreds of microphones are placed at precise locations on the surface of the earth or floating on the surface of the water. Combining the hundreds of measurements for each source location and repeating the measurements after moving the source hundreds of times can produce a fairly accurate representation of the subsurface geometry. A two-dimensional seismic survey, involving a simple array of surface geophones or hydrophones, will show large subsurface features. A more expensive three-dimensional survey, with multiple lines of geophones or hydrophones, as shown in below, can show subtler reservoir characteristics and smaller structural features. This data can be further processed to allow visualization of subsurface geology, hydrocarbons, and even potential well locations.
Once a promising feature has been identified, either by surface observation or by gravity, magnetic, or seismic interpretation, an exploration well must be drilled to confirm the discovery—or more likely, a duster, or nondiscovery. Better technology and wider data coverage have increased chances of discovery from 10% a few decades ago to 30% or more today.
The process of drilling an exploration well is deceptively simple. Drilling a producing well (or developmental well) is similar to drilling an exploration well. The section on Gas Production describes this process in detail.
Wireline logging surveys follow the drilling of exploration wells. A spool and data-transmission cable lower sophisticated sensors into the well bore (see below). The sensors measure various physical and chemical properties of the rock layers and the fluids present in the pores of the rock. Common measurements include resistivity, sonic porosity, and nuclear radiation and density. Oil and gas are more resistant to electricity conduction than water, so measuring electrical resistance of rock over constant intervals can identify the fluids in the rock. Sound waves travel faster in dense materials. Thus, rocks with large amounts of pore space will have a slower acoustic speed. The sensor measures this relationship, and sophisticated computation can estimate the porosity of various rock layers. Because shales contain a higher concentration of radioactive elements, measuring natural radiation of rocks can identify shales versus other sedimentary zones. This differentiates potential source and trap rocks from reservoir rocks. Nuclear logging surveys can determine rock density, which can help identify the rock type.
Gas Production
Gas Production
 Gas production methodology is a function of the type of gas reservoir and the production stage in the life of the particular reservoir. A simple oil and gas reservoir may initially produce high volumes of oil relative to gas, but as the oil production and reservoir pressure decline, an increasing amount of gas may be produced. This increases the gas/oil ratio (GOR) of the produced hydrocarbons. Reservoir management may dictate producing oil first, using the natural gas pressure to increase oil recovery rates. As the GOR increases, reservoir pressure may be too low for natural production, and without secondary production methods, production will eventually cease from the reservoir. In this case, the total recovery factor could be as low as 20%–40%, leaving 60%–80% of the original hydrocarbons—both oil and gas—in place.Field development plans incorporate reservoir models derived from all available reservoir information. Petroleum engineers use these models to plan the location of field development wells. The figures below show a typical onshore and offshore field development. The main difference between the two developments is that offshore development wells are usually tied to a fixed platform with a set number of slots or well bores. An offshore platform may have a large number of slots, each leading to a well deviating away from the platform, draining a specific portion of the reservoir.
The process of drilling a gas well is quite easy to understand. The sequence is shown below.  |
Gas Pricing
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:
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.
Group 2:
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.
Group 3:
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 gauaranteed 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.
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.
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
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.
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:
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.
Group 2:
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.
Group 3:
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 gauaranteed 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.
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.
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
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.
Gas Pricing
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:
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.
Group 2:
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.
Group 3:
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 gauaranteed 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.
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.
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
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.
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:
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.
Group 2:
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.
Group 3:
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 gauaranteed 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.
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.
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
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.
Gas Pricing
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:
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.
Group 2:
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.
Group 3:
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 gauaranteed 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.
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.
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
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.
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:
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.
Group 2:
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.
Group 3:
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 gauaranteed 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.
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.
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
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.
What is Natural Gas?
What is Natural Gas?
Natural gas, crude oil, and coal are collectively known as hydrocarbons. Also called petroleum compounds, hydrocarbons are made up of the elements hydrogen and carbon, plus impurities. A wide variety of distinctly different hydrocarbon compounds, each with a different proportion of these two main elements, is encompassed within the general terms natural gas and crude oil.
The lower the number of carbon molecules, the lighter the compound, and the more likely the hydrocarbon will be found in the gaseous phase. Crude oils contain longer chains of carbon molecules and are heavier than gas; they are more likely to be found in liquid phase. Coal is usually found in the solid phase and contains even longer chains of carbon molecules.
As a strict definition, natural gas consists of hydrocarbons that remain in the gas phase (not condensable into liquids) at 20°C and atmospheric pressure, conditions considered to be standard temperature and pressure (STP). This effectively limits the definition to components with four or fewer carbon molecules: methane (C1H4), ethane (C2H6), propane (C3H8), and butane (C4H10). Hydrocarbons with more carbon molecules are liquid at standard conditions but may exist in gaseous phase in the reservoir. A more practical definition of natural gas (see figure below) includes the C5+ components that are produced with natural gas. Pentane (C5H12) begins the series that includes condensates. Natural gas definitions do not include components heavier than hexadecane (C16H34) that are produced and found as liquid or solid waxy compounds. These may be considered compounds in the crude oil family.
Methane is the main component of natural gas, usually accounting for 70%–90% of the total volume produced. If gas contains more than 95% methane, it is sometimes termed dry or lean gas, and it will produce few, if any, liquids when brought to the surface. Gas containing less than 95% methane and more than 5% of heavier hydrocarbon molecules (ethane, propane, and butane) is sometimes called rich gas or wet gas. This gas usually produces hydrocarbon liquids during production.
Methane is the most common component transported by pipelines and converted to liquefied natural gas (LNG). LNG is the liquid product produced by cooling methane to –161.5°C. Methane may also be converted to liquid fuels through gas-to-liquids (GTL) processes. Methane is the main component of natural gas that power stations and industrial and residential users consume.
Liquefied petroleum gas (LPG) refers specifically to propane and butane when they are stored, transported, and marketed in pressurized containers.
Natural gas liquids (NGLs) include components that remain gaseous at both reservoir and surface conditions. These include ethane, propane, and butane, and components that exist with the gas in the reservoir but become liquid on the surface, such as condensates and natural gasoline. Condensates are low-density liquid mixtures of pentanes and other heavier hydrocarbons.
Natural gas can also contain nonhydrocarbon components such as carbon dioxide (CO2), hydrogen sulfide (H2S), hydrogen, nitrogen, helium, and argon. All of these impurities, especially the first two, CO2 and H2S, must be removed from the natural gas stream prior to sale.
Gases with high levels of H2S are also called sour gas, referring to the sour smell of sulfur. Conversely, gases with low levels of H2S are termed sweet gases and can be directly sold to consumers. Sour gases usually require treatment to remove sulfur prior to sale.
Please watch the video below to hear the author explain these concepts in detail. The video is the first module of Natural Gas Dynamics , an online natural gas / LNG course developed by the author
Natural gas, crude oil, and coal are collectively known as hydrocarbons. Also called petroleum compounds, hydrocarbons are made up of the elements hydrogen and carbon, plus impurities. A wide variety of distinctly different hydrocarbon compounds, each with a different proportion of these two main elements, is encompassed within the general terms natural gas and crude oil.
The lower the number of carbon molecules, the lighter the compound, and the more likely the hydrocarbon will be found in the gaseous phase. Crude oils contain longer chains of carbon molecules and are heavier than gas; they are more likely to be found in liquid phase. Coal is usually found in the solid phase and contains even longer chains of carbon molecules.
As a strict definition, natural gas consists of hydrocarbons that remain in the gas phase (not condensable into liquids) at 20°C and atmospheric pressure, conditions considered to be standard temperature and pressure (STP). This effectively limits the definition to components with four or fewer carbon molecules: methane (C1H4), ethane (C2H6), propane (C3H8), and butane (C4H10). Hydrocarbons with more carbon molecules are liquid at standard conditions but may exist in gaseous phase in the reservoir. A more practical definition of natural gas (see figure below) includes the C5+ components that are produced with natural gas. Pentane (C5H12) begins the series that includes condensates. Natural gas definitions do not include components heavier than hexadecane (C16H34) that are produced and found as liquid or solid waxy compounds. These may be considered compounds in the crude oil family.
Methane is the main component of natural gas, usually accounting for 70%–90% of the total volume produced. If gas contains more than 95% methane, it is sometimes termed dry or lean gas, and it will produce few, if any, liquids when brought to the surface. Gas containing less than 95% methane and more than 5% of heavier hydrocarbon molecules (ethane, propane, and butane) is sometimes called rich gas or wet gas. This gas usually produces hydrocarbon liquids during production.
Methane is the most common component transported by pipelines and converted to liquefied natural gas (LNG). LNG is the liquid product produced by cooling methane to –161.5°C. Methane may also be converted to liquid fuels through gas-to-liquids (GTL) processes. Methane is the main component of natural gas that power stations and industrial and residential users consume.
Liquefied petroleum gas (LPG) refers specifically to propane and butane when they are stored, transported, and marketed in pressurized containers.
Natural gas liquids (NGLs) include components that remain gaseous at both reservoir and surface conditions. These include ethane, propane, and butane, and components that exist with the gas in the reservoir but become liquid on the surface, such as condensates and natural gasoline. Condensates are low-density liquid mixtures of pentanes and other heavier hydrocarbons.
Natural gas can also contain nonhydrocarbon components such as carbon dioxide (CO2), hydrogen sulfide (H2S), hydrogen, nitrogen, helium, and argon. All of these impurities, especially the first two, CO2 and H2S, must be removed from the natural gas stream prior to sale.
Gases with high levels of H2S are also called sour gas, referring to the sour smell of sulfur. Conversely, gases with low levels of H2S are termed sweet gases and can be directly sold to consumers. Sour gases usually require treatment to remove sulfur prior to sale.
Please watch the video below to hear the author explain these concepts in detail. The video is the first module of Natural Gas Dynamics , an online natural gas / LNG course developed by the author
Natural Gas Units & Online Calculator
Natural Gas Units & Online Calculator
Contrary to popular opinion, gas is not generally sold per unit of volume, but rather per unit of energy that can be produced by burning the gas. End-use consumers of gas are interested in the heat energy that combusting the gas will generate. Since the heat energy of the gas is related to the relative proportion of “lighter” methane versus “heavier” ethane, propane, butane, pentane, and other components, heat energy is not a constant value between different gas sources.
The heat energy of a particular gas stream is measured by units of calorific value, which is defined by the number of heat units released when a unit volume of the gas burns. Typical units of calorific value are British thermal units (Btu), joules (J), and kilocalories (kcal).
Most industrial and residential customers receive gas via a pipeline connection and a gas meter that measures the volume of gas delivered. This volume measurement is subsequently converted, using the average calorific value per volume factor, into number of energy units consumed by the end user and multiplied by the price per unit of energy to determine the billed amount.
Worldwide, the cost of gas to the customer is commonly specified in dollars per British thermal unit. A British thermal unit is the energy required to raise the temperature of 1 pound of water by 1°F. For larger industrial customers, the abbreviations MBtu (thousand or 10x3 Btu) or MMBtu (million or 10x6 Btu) are more commonly used. In the United Kingdom, gas is charged to residential customers at a price per therm, which is equivalent to 100,000 Btu.
Gas volumes are usually measured in multiples of cubic feet (ft3) or cubic meters (m3). Gas reserves are expressed in billion cubic feet (bcf) (109), or trillion cubic feet (tcf) (10x12), or, in the case of countries using the metric system, billion cubic meters (bcm). Gas volume produced or consumed is often expressed in million cubic feet (MMcf), (10x6), and Mcf (thousand cubic feet). Gas volume can also be expressed in million cubic feet per day (MMcfd), sometimes written as MMscfd to denote standard conditions, and its metric counterpart, billion cubic meters per day (bcmd). (M is commonly used to designate 1,000, which is based on the Roman numeral system. Thus MM denotes 1,000 x 1,000, or 1 million (10x6). In the metric system, k also refers to 1,000. The energy industry uses both M and k. Some companies use the lower case m to denote 1,000; thus mmcfd would be equal to MMcfd.
As stated earlier, conversion from volume to energy requires knowledge of the average calorific value of the particular gas. Natural gas from different fields, and sometimes different reservoirs in the same field, can have different proportions of hydrocarbon components and thus varying calorific values. A factor of 1,000 Btu/ft3 is commonly used.
Crude oil has a calorific value of 5.4 MMBtu to 5.8 MMBtu per barrel (bbl) of oil, depending on the composition of the oil. It is often necessary and useful to convert gas volume into energy equivalent barrels of oil using barrel of oil equivalent (boe) units. This is commonly done when both oil and gas are found and produced in the same reservoir, making it easier to estimate the total reserves or production volumes.
Conversion Tools
Natural gas units can be confusing. To make conversions easier, Natgas.info has created an app for the iPhone/iPad as well as this online gas units converter.
To download the app, please go to itunes and search for GasUnits or click on link below:
To use the online converter tool below, first select the appropriate energy content per cubic feet of gas and per barrel of oil. If you do not know the exact factors to use, the factors 1 million Btu = 1000 cf and 1 barrel of oil equivalent = 5,800 cf is a common approximation.
Next, select whether the units to be converted are volumes (cubic feet, meters, etc) or rates (cubic feet per day) or end products (volumes of GTL or LNG liquids or watts of electricity). The first calculator is for volumes, and the second calculator can be used for rates and end products.
Lastly, pick the input units ("Units In"), enter the input value, and then pick the desired output unit ("Unit Out"). Click on "Calculate" to make the conversion.
Contrary to popular opinion, gas is not generally sold per unit of volume, but rather per unit of energy that can be produced by burning the gas. End-use consumers of gas are interested in the heat energy that combusting the gas will generate. Since the heat energy of the gas is related to the relative proportion of “lighter” methane versus “heavier” ethane, propane, butane, pentane, and other components, heat energy is not a constant value between different gas sources.
The heat energy of a particular gas stream is measured by units of calorific value, which is defined by the number of heat units released when a unit volume of the gas burns. Typical units of calorific value are British thermal units (Btu), joules (J), and kilocalories (kcal).
Most industrial and residential customers receive gas via a pipeline connection and a gas meter that measures the volume of gas delivered. This volume measurement is subsequently converted, using the average calorific value per volume factor, into number of energy units consumed by the end user and multiplied by the price per unit of energy to determine the billed amount.
Worldwide, the cost of gas to the customer is commonly specified in dollars per British thermal unit. A British thermal unit is the energy required to raise the temperature of 1 pound of water by 1°F. For larger industrial customers, the abbreviations MBtu (thousand or 10x3 Btu) or MMBtu (million or 10x6 Btu) are more commonly used. In the United Kingdom, gas is charged to residential customers at a price per therm, which is equivalent to 100,000 Btu.
Gas volumes are usually measured in multiples of cubic feet (ft3) or cubic meters (m3). Gas reserves are expressed in billion cubic feet (bcf) (109), or trillion cubic feet (tcf) (10x12), or, in the case of countries using the metric system, billion cubic meters (bcm). Gas volume produced or consumed is often expressed in million cubic feet (MMcf), (10x6), and Mcf (thousand cubic feet). Gas volume can also be expressed in million cubic feet per day (MMcfd), sometimes written as MMscfd to denote standard conditions, and its metric counterpart, billion cubic meters per day (bcmd). (M is commonly used to designate 1,000, which is based on the Roman numeral system. Thus MM denotes 1,000 x 1,000, or 1 million (10x6). In the metric system, k also refers to 1,000. The energy industry uses both M and k. Some companies use the lower case m to denote 1,000; thus mmcfd would be equal to MMcfd.
As stated earlier, conversion from volume to energy requires knowledge of the average calorific value of the particular gas. Natural gas from different fields, and sometimes different reservoirs in the same field, can have different proportions of hydrocarbon components and thus varying calorific values. A factor of 1,000 Btu/ft3 is commonly used.
Crude oil has a calorific value of 5.4 MMBtu to 5.8 MMBtu per barrel (bbl) of oil, depending on the composition of the oil. It is often necessary and useful to convert gas volume into energy equivalent barrels of oil using barrel of oil equivalent (boe) units. This is commonly done when both oil and gas are found and produced in the same reservoir, making it easier to estimate the total reserves or production volumes.
Conversion Tools
Natural gas units can be confusing. To make conversions easier, Natgas.info has created an app for the iPhone/iPad as well as this online gas units converter.
To download the app, please go to itunes and search for GasUnits or click on link below:
To use the online converter tool below, first select the appropriate energy content per cubic feet of gas and per barrel of oil. If you do not know the exact factors to use, the factors 1 million Btu = 1000 cf and 1 barrel of oil equivalent = 5,800 cf is a common approximation.
Next, select whether the units to be converted are volumes (cubic feet, meters, etc) or rates (cubic feet per day) or end products (volumes of GTL or LNG liquids or watts of electricity). The first calculator is for volumes, and the second calculator can be used for rates and end products.
Lastly, pick the input units ("Units In"), enter the input value, and then pick the desired output unit ("Unit Out"). Click on "Calculate" to make the conversion.
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