U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
International Energy Outlook 2013
In the IEO2013 Reference case, natural gas is the world's fastest-growing fossil fuel, with consumption increasing from 113.0 trillion cubic feet in 2010 to 185.0 trillion cubic feet in 2040. Growth in consumption occurs in every IEO region and is most concentrated in non-OECD countries, where demand increases more than twice as fast as in OECD countries (Figure 40). Non-OECD producers account for more than 70 percent of the total growth in world natural gas production from 2010 to 2040.
Natural gas continues to be favored as an environmentally attractive fuel compared with other hydrocarbon fuels. It is the fuel of choice for the electric power and industrial sectors in many of the world's regions, in part because of its lower carbon intensity compared with coal and oil, which makes it an attractive fuel source in countries where governments are implementing policies to reduce greenhouse gas emissions. In addition, it is an attractive alternative fuel for new power generation plants because of relatively low capital costs and the favorable heat rates for natural gas generation. In the Reference case, total world consumption of natural gas for industrial uses increases by an average of 1.5 percent per year through 2040, and consumption in the electric power sector grows by 2.0 percent per year. The industrial and electric power sectors together account for 77 percent of the total projected increase in natural gas consumption, and together they account for 74 percent of total natural gas consumption in 2040, up slightly from 73 percent in 2010.
Growth in natural gas consumption is particularly strong in non-OECD countries, where economic growth leads to increased demand over the projection period. Consumption in non-OECD countries grows by an average of 2.2 percent per year through 2040, more than twice as fast as the 1.0-percent annual growth rate for natural gas demand in the OECD countries. As a result, non-OECD countries account for 72 percent of the total world increment in natural gas consumption, as the non-OECD share of world natural gas use increases from 51 percent in 2010 to 59 percent in 2040.
Abundant natural gas resources and robust production contribute to the strong competitive position of natural gas among other energy sources. In the Reference case, the largest production increases from 2010 to 2040 (Figure 41) occur in non-OECD Europe and Eurasia (18.9 trillion cubic feet), the OECD Americas (15.9 trillion cubic feet), and the Middle East (15.6 trillion cubic feet). The United States and Russia each increase natural gas production by around 12 trillion cubic feet, together accounting for nearly one-third of the total increase in world gas production. Russia's production growth is supported primarily by increasing exploitation of resources in the country's Arctic and eastern regions. U.S. production growth mainly comes from shale resources (see "What is shale gas and how is it produced?").
Although there is more to learn about the extent of the world's tight gas, shale gas, and coalbed methane resource base, the IEO2013 Reference case projects a substantial increase in those supplies—especially in the United States and also in Canada and China (Figure 42). In the United States, one of the keys to increasing natural gas production has been advances in the application of horizontal drilling and hydraulic fracturing technologies, which have made it possible to develop the country's vast shale gas resources and have contributed to a near doubling of estimates for total U.S. technically recoverable natural gas resources over the past decade. In the Reference case, shale gas accounts for 50 percent of U.S. natural gas production in 2040. Tight gas, shale gas, and coalbed methane resources in Canada and China account for more than 80 percent of total domestic production in 2040 in the Reference case (see "International shale gas resources").
Shale gas refers to natural gas found in shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. While the technologies have been known for decades, it has only been over the past few years that the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States, and shale production techniques could be applied globally.
Shale gas is found in shale formations, or plays, that contain significant accumulations of natural gas and have similar geologic and geographic properties. Experience and information gained from developing the Barnett Shale in Texas have improved the efficiency of shale gas development around the United States. Geophysicists and geologists identify suitable well locations in areas with potential for economical gas production by using surface and subsurface geology and seismic techniques to generate maps of the subsurface.
Hydraulic fracturing (commonly called fracking) is a technique in which water, chemicals, and sand are pumped into a well to release the hydrocarbons in a shale formation by opening cracks (fractures) in the rock and allowing the natural gas to flow from the shale into the well. When used in conjunction with horizontal drilling, hydraulic fracturing enables gas producers to extract shale gas economically.
Liquefied natural gas (LNG) accounts for a growing share of world natural gas trade in the Reference case. World LNG trade more than doubles, from about 10 trillion cubic feet in 2010 to around 20 trillion cubic feet in 2040. Most of the increase in liquefaction capacity occurs in Australia and North America, where a multitude of new liquefaction projects are planned or under construction, many of which will become operational within the next decade. At the same time, existing facilities in North Africa and Southeast Asia have been underutilized or are shutting down because of production declines at many of the older fields associated with the liquefaction facilities, and because domestic natural gas consumption is more highly valued than exports.
World natural gas consumption
OECD natural gas consumption
Annual natural gas consumption in the OECD Americas region rises steadily to 41.6 trillion cubic feet in 2040 (Figure 43), including increases of 4.2 trillion cubic feet from 2010 to 2020 (1.4 percent per year) and 8.2 trillion cubic feet from 2020 to 2040 (1.1 percent per year), and accounts for 60 percent of the total increase for OECD countries and 17 percent of the total increase for the world over the projection period. Although natural gas consumption grows at faster rates in other regions, OECD Americas remains the world's largest regional consumer of natural gas through 2040.
The United States—the world's largest consumer of natural gas—has the region's highest projected annual consumption growth in absolute terms (Figure 44). U.S. natural gas consumption increases by 5.8 trillion cubic feet through 2040, accounting for 46 percent of the region's total growth. Projections for combined annual natural gas consumption in Mexico and Chile include absolute growth in the two countries of 4.7 trillion cubic feet (38 percent of total regional growth), followed by Canada (2.0 trillion cubic feet, or 16 percent of the OECD Americas total).
To gain a better understanding of potential international shale gas resources, EIA commissioned Advanced Resources International, Inc. (ARI) to assess shale gas resources. In April 2011, ARI estimated recoverable resources of 5,760 trillion cubic feet of wet natural gas.22
In June 2013, EIA released a second report, Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Other than the United States. The new report updates the 2011 report and expands the coverage. The 2013 report also covers both shale gas and oil resources in shale formations. It focuses on regions that have relatively near-term promise for shale resource development and that have sufficient geologic data on which to base a resource estimate. Estimated risked recoverable resources covered in the 2013 report, including the United States, total 345 billion barrels of oil and 7,299 trillion cubic feet of natural gas. The updated natural gas resource estimate is 10 percent higher than the gas resource estimate in the 2011 report. Additionally, even with the expanded geographic coverage in the 2013 report, there are many important shale formations that it does not assess, such as those underlying large oil fields in the Middle East and the Caspian region.
The resource estimate for China is 13 percent lower in the 2013 report than in the 2011 report, despite covering more basins and more formations. The 2013 report covers 18 formations in 7 basins in China, as compared with 4 formations in 2 basins in the 2011 report. The main downward revision to the estimated risked recoverable resources for China was to the resources in the Tarim Basin. New data gathered since the 2011 report indicate that much of the basin is deeper than previously thought, putting much of the estimated in-place resources just outside of what is currently considered to be commercially producible (although future advances in drilling and completion technology could make production from deeper parts of the basin commercially viable).
Estimates of risked recoverable resources for Australia are 10 percent higher in the 2013 report (437 trillion cubic feet) than in the 2011 report (396 trillion cubic feet), in part because of the expanded coverage of the 2013 report. The Georgina and Beetaloo basins, which were not covered in the 2011 report, add 57 trillion cubic feet to Australia's total estimated risked recoverable resources in the 2013 report. Upward revisions to estimates for the Cooper and Canning basins also contribute to the overall increase. While the remote Canning Basin still remains largely unexplored, the Cooper Basin has been a major oil and gas producing area for years, and initial results from vertical shale test wells have been encouraging.
IEO2013 reflects production from many of the shale gas formations assessed in the two ARI studies. Shale gas production already is occurring outside the United States (in Canada) and is expected to begin in other countries with large technically recoverable resources, such as China, Australia, Mexico, and parts of OECD Europe. The timing and rate of production growth in individual countries remain uncertain, with technology transfer and above-ground factors expected to play a role.
Estimates of shale gas resources outside the United States are relatively uncertain, given that the available data are sparse. Resource estimates will continue to change as development progresses and more data become available. Even in the United States, where tight oil and shale gas production has been robust for several years, there still is considerable uncertainty about the ultimate size of U.S. resources. Resource estimates in the 2013 ARI report represent a moderately conservative resource for the basins reviewed. The methodology, which is described in more detail in the 2013 ARI report, is not directly comparable with more detailed resource assessments based on monthly production data from hundreds or thousands of wells, which provide a probabilistic range of the technically recoverable resource.
Although the United States has the highest absolute growth in natural gas consumption, the growth in Mexico and Chile combined reflects the highest rate of increase over the projection period, at 3.6 percent per year. This is the highest percentage growth rate among all the IEO2013 OECD countries and country groupings, including the United States (0.7 percent per year) and Canada (1.7 percent per year). Increasingly, Mexico has serviced its growing demand for power generation with gas-fired units supplied by pipeline imports from the United States, particularly since 2011 . The growth of Mexico's overall natural gas consumption has outstripped its production growth, causing its net imports to rise over time . In Chile, approval has recently been granted to expand regasification capacity at the LNG plant in Quintero Bay by 50 percent, from 353.1 million cubic feet per day to 529.7 million cubic feet per day .
More than one-half of the growth in total annual natural gas consumption from 2010 to 2040 in the OECD Americas comes from the electric power sector (6.1 trillion cubic feet) in the IEO2013 Reference case, and more than half of the consumption growth in the electric power sector (3.1 trillion cubic feet) occurs in Mexico and Chile. More than 70 percent (2.1 trillion cubic feet) of the remaining growth in natural gas use for electric power in the OECD Americas through 2040 occurs in the United States. The recent decline in U.S. natural gas prices will reduce the overall cost of electricity generation through 2040. However, a number of other factors are likely to affect the degree to which natural gas and electricity prices are linked, such as electricity transmission and distribution systems, as well as power pricing and purchasing mechanisms. In addition to the increased availability of supply at lower prices, the U.S. electric sector's consumption of natural gas will be spurred by the retirement of 49 gigawatts of coal-fired generating capacity by 2022 .
Industrial consumption growth also adds significantly to the overall growth in OECD Americas natural gas consumption through 2040. Industrial consumption grows by 2.1 trillion cubic feet from 2010 to 2020, with 1.5 trillion cubic feet (73 percent) added in the United States, where industrial consumption increases at an average annual rate of 1.8 percent. However, growth in industrial use of natural gas in the United States slows from 2020 to 2040, rising by only 0.8 trillion cubic feet, or an average of 0.4 percent per year. Natural gas gradually loses some of its competitive advantage among U.S. industrial consumers, as international competition for its use increases and prices rise as shale gas production occurs in resources that are more expensive and harder to produce . Industrial consumption growth also slows in Canada—from 1.7 percent annually in the 2010-2020 period to 1.3 percent annually from 2020 to 2040—but increases in Mexico and Chile, from 1.8 percent to 2.8 percent annually during those two periods.
Natural gas consumption in OECD Europe grows by 0.7 percent per year on average, from 19.8 trillion cubic feet in 2010 to 24.5 trillion cubic feet in 2040 (Figure 45)—the lowest growth rate over the period, both in the OECD region and in the world. In comparison, OECD Europe's renewable energy consumption increases by an average of 2.0 percent per year, and its consumption of both liquid fuels and coal declines through 2040. The decline in demand for energy from coal and liquids results in an increase in the natural gas share of OECD Europe's total energy consumption, from about 25 percent in 2010 to 27 percent in 2040.
More than half of OECD Europe's 4.7 trillion cubic feet of growth in total natural gas consumption from 2010 to 2040 comes from the electric power sector, at 2.7 trillion cubic feet. Although the amount of natural gas consumed for electric power production increases by an average of only 0.4 percent per year from 2010 to 2020, it increases by 1.7 percent per year from 2020 to 2040, as economies recover from the global recession that began in 2008.
Many governments in OECD Europe have made commitments to reduce greenhouse gas emissions to 20 percent below 1990 levels by 2020 and have endorsed the objective of lowering emissions to between 80 and 95 percent below 1990 levels by 2050 . Natural gas potentially has two roles to play in reducing carbon dioxide emissions in OECD Europe's electric power sector: as a replacement fuel for more carbon-intensive coal-fired generation and as a backup for intermittent generation from renewable energy sources.
Although there are many incentives for using natural gas more heavily in the electric power sector, growth has been hampered by a lack of progress in regulatory reforms in OECD Europe that would make natural gas more competitive in electric power markets. Such reforms would include measures to increase spot trading and make natural gas markets more flexible by making it easier for market participants to purchase and transmit gas supplies (see "Natural gas pricing mechanisms around the world"). Although OECD Europe is largely expected to continue pricing natural gas via long-term indexed contracts in the near term, some developments—such as a recently signed deal between Germany's Wintershall and Norway's Statoil—signal movement toward spot market pricing . Presumably, the impact of such reforms, as well as the increased use of natural gas to reduce carbon dioxide emissions from electric power generation, would occur for the most part after 2025. Additionally, recent actions by some European governments to reduce their reliance on nuclear power in the wake of Japan's Fukushima Daiichi nuclear disaster will provide an additional boost to both natural gas and renewable energy use in electricity generation. In the IEO2013 Reference case, an increase of 1.7 percent per year in natural gas consumption for power generation from 2020 to 2040 is higher than for any other energy source used in the sector.
Prices and pricing mechanisms for natural gas vary around the world. Today, the three most common pricing mechanisms are oil-linked pricing, regulated pricing, and competitive market pricing (or gas-on-gas competition). Under oil-linked pricing, natural gas generally is traded under long-term contracts with prices linked by formula to either crude oil prices or oil product prices, usually with some discount for the natural gas price relative to the oil price. Regulated prices, which are set by governments, can reflect production and other costs or provide subsidies for natural gas consumers. Under competitive market pricing, trading points or hubs are established in market areas, and competition among various suppliers and consumers of natural gas determines the price. Currently there is no globally integrated market for natural gas, and different pricing mechanisms predominate in different regional markets. As discussed below, however, markets are changing, and the move to more competitive natural gas markets may be inevitable. The timing of such a transition remains uncertain.
Historically, the regulation of U.S. natural gas prices was based on the cost of providing the natural gas (i.e., cost of service). Pipeline companies bought gas from producers at a regulated wellhead price, stored their gas and shipped it via their own facilities, and then sold it after transport, bundling the cost of the gas with its shipping and storage costs into a single price. By 1993, the U.S. natural gas industry had largely been deregulated. Wellhead prices were no longer set by the government, and pipeline companies could no longer bundle services but were required to offer transportation and storage services to third parties on a nondiscriminatory basis. Natural gas trade flourished, and multiple pricing points developed across the United States and Canada, the most active and publicized of which is the Henry Hub in Louisiana.
Until 2005, even with no direct linkage between oil prices and natural gas prices, the two tended to move together, with the market prices for oil (in dollars per barrel) and natural gas (in dollars per million Btu) maintaining a relatively stable ratio of around 7:1, with natural gas priced at a slight discount relative to the oil price on a Btu basis.23 However, as oil prices climbed from an average of $56 per barrel in 2005 to an average of $100 per barrel in 2008, the discount for natural gas relative to oil also grew, from the 7:1 ratio in 2005 to 11:1 in 2008. After 2008, the natural gas discount relative to oil widened further, as oil prices remained relatively high while growing U.S. shale gas production helped to weaken natural gas prices. The oil-to-gas price ratio grew to an average of more than 35:1 in 2012, with a Btu of crude oil selling for more than five times the price for a Btu of natural gas. In EIA's Annual Energy Outlook 2013 Reference case, the U.S. price differential narrows gradually to a ratio of 21:1 in 2040, as shale gas production moves to more expensive and difficult-to-produce resources and natural gas prices rise.
In Europe, natural gas historically has been traded under long-term contracts with prices linked to oil product prices (mainly diesel and heavy fuel oil) at a small discount. As in the United States, Europe has largely deregulated its natural gas industry. Deregulation was essentially completed in the United Kingdom by 2000, and more recently, European Union directives have deregulated natural gas prices in much of Continental Europe.24
Since deregulation began, several natural gas trading points have developed across Europe. The oldest, most active, and best known is the National Balancing Point (NBP) in the United Kingdom. However, hub pricing for natural gas has not yet become universal in Europe as it is in the United States and Canada. Pricing in Europe at present is a mix of natural gas purchased on spot markets at hub prices, gas purchased under long-term contracts with prices linked to hub prices, and gas purchased under long-term contracts with prices linked to oil prices. Through 2005, contract and spot prices for natural gas in Europe were generally lower than the prices in North America. More recently, European natural gas prices have been significantly higher than North American prices, as the natural gas discount relative to oil in Europe has grown only moderately in comparison with the deeper discount of U.S. natural gas prices. The ratio of oil prices to natural gas prices in Europe grew from between 8:1 and 9:1 in 2005 to between 10:1 and 12:1 in 2012.
In Asia, natural gas has been traded in the past under long-term contracts, with gas prices linked to crude oil prices with some discount. Asia's natural gas markets are much less integrated than those in Europe and North America, with fewer pipelines, which are governed by a number of different nations and regulations. The deregulation of the natural gas sector that helped to propel market development in North America and Europe is, so far, generally absent in Asia. However, there have been some recent changes in Asian markets. Asian buyers have gained more destination flexibility, and the volumes of LNG bought and sold on the spot market and under short-term contracts have increased. Asian buyers also have signed contracts to buy LNG from the United States, at prices linked to the Henry Hub price rather than to oil prices. At the same time, s-curves (contract terms that limit the effect of high oil prices on contract prices for natural gas) have been virtually eliminated from contracts in Asia since 2008, helping to sustain prices well above those in both North America and Europe.
Recent increases in natural gas supplies have provided an opportunity for the development of competitive natural gas markets, and global development of shale gas could hasten the advent of competitive pricing regimes around the world. Regulated natural gas prices and prices linked to oil are gradually giving way to competitive natural gas pricing, as seen first in North America and then in the United Kingdom. The transition is still in progress in Continental Europe, where the share of the natural gas market traded under hub market prices is likely to continue to grow. As regional Asian trade and consumption of LNG and natural gas increase, it is virtually inevitable that a natural gas hub will also develop in Asia, even if it is not currently apparent how or where. China, Japan, and Singapore (among other Asian nations) have expressed interest in developing such a hub. Finally, as natural gas trading hubs grow, natural gas increasingly will compete economically worldwide, based on the balance of supply and demand for natural gas itself, without reference to oil prices.
Natural gas consumption in OECD Asia grows on average by 1.3 percent per year from 2010 to 2040, from 6.7 trillion cubic feet to 9.9 trillion cubic feet. Over the projection period, natural gas consumption in Japan increases by an average of 1.0 percent per year, as compared with 1.7 percent for Australia and New Zealand combined and also for South Korea. As a result, Japan's share of the OECD Asia region's total natural gas consumption declines from 58 percent in 2010 to 53 percent in 2040.
From 2010 to 2020, natural gas consumption in Japan rises at a 1.8-percent annual rate—the highest rate in OECD Asia—led by demand in the electric sector, where consumption increases by 2.3 percent annually, from 2.2 trillion cubic feet in 2010 to 2.7 trillion cubic feet in 2020 (Figure 46). Japan has relied primarily on LNG spot cargo shipments to offset the loss of nuclear generating capacity that occurred when the country shut down a large part of its nuclear generation capacity after the Fukushima Daiichi power reactors were severely damaged by the March 2011 earthquake and tsunami. All but two of the country's 50 reactors remain offline to date . Japan receives LNG imports from 32 terminals, with 8.7 trillion cubic feet of total annual sendout capacity. Natural gas consumption has received additional priority in Japan as a way to reduce carbon dioxide emissions.
From 2020 to 2040, Japan's economic growth rate slows to 0.3 percent per year, by far the lowest rate in the region, as a result of its declining population and aging work force. With its nuclear generation capacity assumed to return to service in the IEO2013 Reference case, annual growth rates for natural gas consumption fall below 2010-2020 levels in every sector, including almost no growth in natural gas consumption for electricity generation. Although Japan's natural gas consumption does not decline between 2020 and 2040, its consumption of energy from liquids and coal does decline. As a result, the natural gas share of Japan's total energy consumption rises from 21 percent in 2020 to nearly 25 percent in 2040.
Unlike Japan, South Korea is expected to increase its natural gas consumption at greater rates after 2020. South Korea's natural gas consumption grows by 0.8 percent per year from 2010 to 2020, after which it accelerates to 2.1 percent per year through 2040. This is largely the result of increasing natural gas consumption in South Korea's electric power sector, where natural gas consumption declines by 0.2 percent per year from 2010 to 2020 as a substantial amount of new nuclear power capacity becomes operational. From 2020 to 2040, natural gas consumption for electricity generation in South Korea increases by 3.2 percent per year on average, from 0.7 trillion cubic feet to 1.3 trillion cubic feet.
Natural gas consumption growth from 2010 to 2040 in Australia and New Zealand combined is fairly constant across all sectors. The two countries have the region's strongest growth in electricity sector natural gas consumption, averaging 2.4 percent per year and more than doubling, from 0.3 trillion cubic feet in 2010 to 0.7 trillion cubic feet in 2040. Australia gradually increases the share of natural gas in its power generation mix in order to reduce its more carbon-intensive coal-fired generation. The two countries' combined share of OECD Asia's total natural gas use for electricity generation grows from 10 percent in 2010 to 13 percent in 2040 in the Reference case.
Non-OECD natural gas consumption
Non-OECD Europe and Eurasia
The countries of non-OECD Europe and Eurasia relied on natural gas for 47.3 percent of their primary energy needs in 2010—the second highest of any country grouping in IEO2013 except the Middle East. Non-OECD Europe and Eurasia consumed a total of 21.8 trillion cubic feet of natural gas in 2010, the most outside the OECD, and more than any other region in the world except the OECD Americas. Russia accounted for 69 percent of the regional total in 2010, consuming 15.0 trillion cubic feet (Figure 47).
In the Reference case, overall natural gas consumption in non-OECD Europe and Eurasia grows at a relatively modest annual rate of 1.0 percent from 2010 to 2040. Slow growth of only 0.6 percent per year is projected from 2010 to 2020, when total consumption rises by only 1.2 trillion cubic feet. The region's natural gas consumption grows by an average of 1.3 percent per year from 2020 to 2040, increasing by a total of 6.8 trillion cubic feet. The trend is especially pronounced outside Russia. In the other countries of non-OECD Europe and Eurasia, natural gas consumption grows by an average of 1.4 percent per year from 2010 to 2040, with consumption for electricity generation increasing by 2.0 percent per year, from 1.8 trillion cubic feet in 2010 to 3.3 trillion cubic feet by 2040.
Natural gas consumption increases slowly through 2040 in Russia. Russia's slow increase in natural gas consumption reflects the country's declining population, as well as a shift away from natural gas to nuclear power in its electricity sector, as the country looks to monetize natural gas through exports to markets in Asia and OECD Europe. These efforts include the recently completed construction of a second pipeline running parallel to the offshore Nord Stream line into Germany , as well as the South Stream pipeline, which after its expected completion in 2015 would transport more than 2.2 trillion cubic feet per year through Bulgaria, Serbia, Hungary, Slovenia, and Italy . Expected efficiency improvements and other demand-side management measures also limit growth in natural gas consumption over the long term. As a result, Russia's projected 0.9-percent average annual growth in natural gas demand from 2010 to 2040 is the lowest outside the OECD and the second lowest in the world, with its share of non-OECD Europe and Eurasia's total regional natural gas consumption falling from 69 percent in 2010 to 65 percent in 2040. Nonetheless, Russia remains the largest national non-OECD consumer of natural gas through 2040 in the IEO2013 Reference case.
Among all regions of the world, the fastest growth in natural gas consumption in the IEO2013 Reference case occurs in non-OECD Asia. Natural gas use in non-OECD Asia increases by an average of 3.3 percent annually, from 13.9 trillion cubic feet in 2010 to almost triple that amount—36.3 trillion cubic feet—in 2040 (Figure 48). During the period, the non-OECD Asia region accounts for more than 30 percent of the total increment in world natural gas use. Non-OECD Asia moves from its current position as the world's fourth-largest natural gas consuming region to the second-largest gas consumer by 2030. Total natural gas consumption increases from less than one-half that of the OECD Americas region in 2010 to nearly 90 percent in 2040, and its share of total world natural gas consumption rises from 12 percent in 2010 to 20 percent in 2040.
Almost two-thirds (61 percent) of non-OECD Asia's growth in natural gas consumption from 2010 to 2040 occurs in China, where total consumption rises by more than 360 percent in the Reference case, from 3.8 trillion cubic feet in 2010 to 17.5 trillion cubic feet in 2040. China's central government is promoting natural gas as a preferred energy source and has set an ambitious target of increasing the share of natural gas in its overall energy mix to 10 percent (or approximately 8.8 trillion cubic feet) by 2020 in order to alleviate pollution from its heavy coal use . In the IEO2013 Reference case, natural gas consumption in China totals 7.8 trillion cubic feet in 2020, or about 5 percent of the country's total energy consumption, as a result of continued growth in consumption of energy from other sources, particularly coal. In 2040, the natural gas share of China's energy consumption is 8 percent—still far less than coal's 55-percent share. In addition, the 5.3-percent average annual growth rate for natural gas consumption from 2010 to 2040 is less than half the 10.3-percent rate for nuclear energy.
The most expansive growth in China's natural gas consumption occurs between 2010 and 2020, averaging 7.5 percent per year before slowing to 4.2 percent from 2020 to 2040, which still is higher than the non-OECD Asia regional average of 3.2 percent from 2020 to 2040. Most of China's initial growth in demand for natural gas comes from the electric power, industrial, and residential sectors, which together account for 91 percent of the increase in the country's natural gas consumption through 2020, including 8.0-percent average annual growth in the electric power sector and 10.9-percent average annual growth in the residential sector. Growth in all three sectors levels off from 2020 to 2040, but they still account for 87 percent of the country's total growth in natural gas consumption during the period.
Natural gas accounted for about 10 percent of India's overall energy consumption in 2010, nearly 2.5 times the share in China's energy mix. India's natural gas consumption averages 2.0-percent annual growth from 2010 to 2040, lower than for all energy sources except coal and only one-fifth of the 10.0-percent annual growth rate for nuclear energy consumption during the period. This results largely from supply constraints, including continued obstacles to reaching agreement on the construction of three pipelines that would provide India with natural gas from fields in Iran, Turkmenistan, and Myanmar . Consequently, the natural gas share of India's total energy consumption declines to 8 percent in 2040, despite consumption increases of 1.0 and 0.9 trillion cubic feet, respectively, in the industrial and electric power sectors.
In the other countries of non-OECD Asia, natural gas accounts for slightly less than one-quarter of overall energy consumption from 2010 through 2040, increasing by an average of 2.1 percent per year from 7.8 trillion cubic feet in 2010 to 14.6 trillion cubic feet by 2040. Although natural gas remains the second-largest source of energy consumption after liquids, its annual growth rate is less than the rates for coal (2.4 percent) and nuclear energy (5.1 percent).
In the Middle East region, natural gas accounted for about one-half of total energy consumption in 2010, more than in any other region. In the IEO2013 Reference case, Middle East natural gas consumption increases by an average of 2.2 percent per year from 2010 to 2040, when it accounts for almost 54 percent of total energy use, the highest share of any IEO2013 world region. The industrial sector accounts for the largest share of natural gas consumption in the Middle East from 2010 to 2040 (Figure 49). Natural gas use in the industrial sector grows by 8.0 trillion cubic feet from 2010 to 2040, or two-thirds of the region's 12.0 trillion cubic feet of total natural gas consumption growth. Industrial sector natural gas consumption rises by an average 2.6 percent per year, more than doubling over the projection period. Natural gas consumption in the electric power sector, by comparison, grows to 7.6 trillion cubic feet in 2040, increasing at an average annual rate of 1.8 percent.
A significant portion of the increase in industrial natural gas consumption—particularly through 2015—is attributed to the use of natural gas in LNG liquefaction plants and in gas-to-liquids (GTL) plants in Qatar—the world's largest LNG supplier. Qatar's two main LNG producers, Qatargas and RasGas, both of which are joint ventures with majority shares held by government-owned Qatar Petroleum, are not expected to expand their annual LNG liquefaction capacity beyond the current 3.75 trillion cubic feet through the construction of new facilities. Rather, any capacity increases are expected to result from improvements at existing facilities .
In the IEO2013 Reference case, Africa's natural gas consumption rises to 8.8 trillion cubic feet in 2040, nearly 2.5 times the 2010 total (Figure 50). The average annual growth rate of natural gas use, at 3.1 percent, is second only to that of nuclear energy, which increases by 6.8 percent per year from 2010 to 2040.
Egypt and Algeria are Africa's two largest consumers and producers of natural gas, together accounting for more than 74 percent of the region's total natural gas consumption and 70 percent of its production in 2010 . Egypt's consumption is expected to be bolstered by government-sponsored efforts to encourage households and businesses to switch to natural gas from petroleum, coal, and liquefied petroleum gas. In addition to a Natural Gas Connections Project in Egypt that is sponsored by the World Bank, the Egyptian government currently requires one-third of the country's 77 trillion cubic feet of proved reserves be set aside for domestic consumption .
The electric power and industrial sectors account for 93 percent of the total increase in Africa's demand for natural gas from 2010 to 2040 and 93 percent of its overall natural gas demand in 2040. The electric power sector alone accounts for 58 percent of the rise in natural gas consumption from 2010 to 2040, from 1.8 trillion cubic feet to 4.8 trillion cubic feet. Almost all of the increase in natural gas use for electricity generation in Africa occurs from 2020 to 2040, averaging 4.6 percent per year, versus an average annual increase of less than 1.0 percent from 2010 to 2020.
Nigeria holds an estimated 182 trillion cubic feet of natural gas proved reserves, the largest in the region and ninth-largest in the world. Most of Nigeria's marketed production is exported as LNG. The remainder is consumed domestically or exported to Benin, Togo, and Ghana via the West African Gas Pipeline, which also connects the nation's gas fields to its capital city, Lagos. About 85 percent of the gas transported through the pipeline is used for electricity generation, according to pipeline operator WAPCo. With an initial capacity of 170 million cubic feet per day, the pipeline is expected to be expanded over time to 460 million cubic feet per day . Algeria holds the world's tenth-largest proved reserves of natural gas and is the world's eighth-largest producer. Like Nigeria, most of Algeria's production is exported, primarily to European consumers through both pipeline networks and LNG shipments .
Central and South America
Natural gas consumption in the non-OECD nations of Central and South America increases by an average of 2.0 percent per year in the IEO2013 Reference case, from 4.9 trillion cubic feet in 2010 to 8.9 trillion cubic feet in 2040 (Figure 51). The electric power sector accounts for one-half of the demand growth from 2010 to 2040, followed by the industrial sector at 30 percent.
Brazil's natural gas consumption grows by an average of 3.9 percent per year from 2010 to 2040, or by a total of 1.9 trillion cubic feet, which is nearly one-half of the overall increase of 4.0 trillion cubic feet for the Central and South America region. A number of projects to expand domestic gas pipelines are planned by the state-owned Petrobras company, as well as efforts to diversify the country's electricity supply away from reliance on hydropower, in order to mitigate the risk of power shortages during dry periods .
The natural gas share of Brazil's overall energy mix grows from 7 percent in 2010 to almost 12 percent in 2040. Nearly two-thirds (62 percent) of the increase in Brazil's natural gas consumption comes from the electric power sector, where natural gas use grows by 600 percent, from 0.2 trillion cubic feet in 2010 to 1.4 trillion cubic feet in 2040. The growth in natural gas consumed for electric power in Brazil averages 11.2 percent per year from 2010 to 2020 and 5.1 percent per year from 2020 to 2040. However, the 12-percent natural gas share of Brazil's overall energy consumption in 2040 remains well below the share in the rest of Central and South America, which is about 30 percent over the entire period.
One of the world's largest endowments of shale gas has been discovered in Argentina, which is also the region's largest consumer of natural gas. Construction of the Gasoducto del Noreste Argentino (GNEA) gas pipeline  is expected to connect Argentina's northern and central provinces with Bolivia's Juana Azurduy integration pipeline, which could provide nearly 1.0 billion cubic feet of natural gas per day to users in Argentina .
World natural gas production
In order to meet the consumption growth in the IEO2013 Reference case, the world's natural gas producers will need to increase supplies by more than 70 trillion cubic feet—or around 65 percent—from 2010 to 2040. Much of the increase in supply is expected to come from non-OECD countries, which in the Reference case account for 73 percent of the total increase in world natural gas production from 2010 to 2040. Non-OECD natural gas production grows by an average of 2.0 percent per year, from 70 trillion cubic feet in 2010 to 126 trillion cubic feet in 2040 (Table 7), while OECD production grows by only 1.3 percent per year, from 41 trillion cubic feet to 61 trillion cubic feet.
Production of tight gas, shale gas, and coalbed methane grows rapidly in the projection, with OECD tight gas, shale gas, and coalbed methane production growing on average by 3.4 percent per year, from 16 trillion cubic in 2010 to 43 trillion cubic feet in 2040. Over the same period, non-OECD production of tight gas, shale gas, and coalbed methane grows from less than 1 trillion cubic feet to 20 trillion cubic feet. However, numerous uncertainties could affect future production of those resources. There is still considerable variation among estimates of recoverable shale gas resources in the United States and Canada, and estimates of recoverable tight gas, shale gas, and coalbed methane for the rest of the world are more uncertain given the sparse data currently available. Moreover, the hydraulic fracturing process used to produce shale gas resources requires significant amounts of water, and in many of the areas that have been identified globally as possessing shale gas resources the available water supplies are limited. Further, environmental concerns add to the uncertainty surrounding access to shale gas resources.
Natural gas production in the OECD Americas grows by 56 percent from 2010 to 2040. The United States, which is the largest producer in the OECD Americas and in the OECD as a whole, accounts for three-quarters of the total regional production growth, with an increase from 21.2 trillion cubic feet in 2010 to 33.1 trillion cubic feet in 2040 (Figure 52). U.S. shale gas production grows from 4.9 trillion cubic feet in 2010 to 16.7 trillion cubic feet in 2040, more than offsetting declines in production of natural gas from other sources. In 2040, shale gas accounts for 50 percent of total U.S. natural gas production in the IEO2013 Reference case, tight gas accounts for 22 percent, and Lower 48 offshore production accounts for 9 percent. The remaining 19 percent comes from coalbed methane, Alaska, and other associated and nonassociated Lower 48 onshore resources.
One of the keys to U.S. production growth is advanced production technologies, especially the combined application of horizontal drilling and hydraulic fracturing techniques that have made the country's vast shale gas resources accessible. Rising estimates of shale gas resources have been the primary factor in nearly doubling the estimated U.S. technically recoverable natural gas resource over the past decade, and U.S. shale gas production has continued to grow despite low natural gas prices. As North American natural gas prices have remained low and liquids prices have risen with international crude oil prices, U.S. shale drilling has concentrated on liquids-rich shales such as the Bakken formation in North Dakota and the Eagle Ford formation in Texas.
Natural gas production in Canada grows by 1.1 percent per year on average over the projection period, from 5.4 trillion cubic feet in 2010 to 7.6 trillion cubic feet in 2040. As in the United States, much of the production growth comes from growing volumes of tight gas and shale gas production. Four proposed LNG liquefaction and export facilities would use feedstock gas from the Montney tight gas and Horn River shale gas formations in western Canada. If all four facilities were built and operated at their pipeline exports of natural gas from Canada to the United States in the Reference case.
Currently, in addition to small but growing volumes of shale gas, Canada also produces small volumes of natural gas from coalbeds and significant volumes from tight reservoirs. In 2010, almost 40 percent of Canada's natural gas production came from tight reservoirs . Most of the country's coalbed methane production is in the province of Alberta, which had more than 11,000 producing coalbed methane wells and 260 billion cubic feet of coalbed methane production in 2010 . In 2001, coalbed methane activity in the province consisted of no more than a few test wells.
Mexico's natural gas production remains fairly flat in the mid-term but more than doubles in the later years of the projection, as production from shale gas resources grows. Total natural gas production increases from 1.8 trillion cubic feet in 2010 to 3.5 trillion cubic feet in 2040. Like Canada and the United States, Mexico is thought to have substantial shale gas resources, the most prospective of which are extensions of the successful Eagle Ford Shale in the United States. However, because the shale resources in Mexico are not as well explored as those in the rest of North America, there is more uncertainty surrounding estimates of their size and producibility. Mexico also faces substantial difficulties in attracting the investment and technology improvements needed to increase natural gas production generally and production from shale resources specifically.
Norway, the Netherlands, and the United Kingdom are by far the three largest producers of natural gas in OECD Europe, accounting for 85 percent of total regional natural gas production in 2010. From 2000 to 2010, production in the Netherlands was fairly flat, as was production by the three largest producers combined, and in OECD Europe as a whole. Stability of total production volumes has been supported by significant growth in Norway's production, which has balanced declines in the United Kingdom's production. That balance will be broken in the mid-term, however, as production declines in the United Kingdom and much of the rest of Europe overwhelm any additional growth in Norway's production. In the IEO2013 Reference case, OECD Europe's natural gas production declines in the mid-term and then begins to grow again in the later part of the projection, as production from tight gas, shale gas, and coalbed methane resources becomes more significant (Figure 53). Overall, natural gas production in OECD Europe in 2040 is about the same as in 2010.
OECD Europe's natural gas production is also buoyed by long-term growth in production in Israel, which became an OECD member country in September 2010 and is included in the OECD Europe totals in IEO2013. In 2010, Israel produced just 55 billion cubic feet of natural gas, but with significant offshore finds in the Levant Basin, including the Tamar and Leviathan fields, it has the potential to produce at least 1 trillion cubic feet per year. Israel's demand for natural gas is limited, however, and actual production growth could be affected by the economics or politics of exporting natural gas.
Natural gas production in the Australia/New Zealand region grows from 1.9 trillion cubic feet in 2010 to 6.7 trillion cubic feet in 2040 in the Reference case, an average rate of 4.3 percent per year. In 2010, Western Australia, including the Northwest Shelf area of Australia's Carnarvon Basin, accounted for around 63 percent of total production in the Australia/New Zealand region , with much of the production used as feedstock at the Northwest Shelf LNG liquefaction facility. Other areas and basins in Australia provided another 28 percent of the region's total production in 2010. New Zealand's natural gas production accounted for around 9 percent of the 2010 regional total.
Coalbed methane from the Bowen-Surat Basin in eastern Australia accounted for between 10 percent and 11 percent of Australia's total natural gas production in 2010 , and its share grows as it provides natural gas supplies to satisfy the area's demand growth and to feed proposed LNG export projects.
Several companies also are pursuing tight gas and shale gas resources in Australia. Both the Perth and Canning basins in the state of Western Australia may hold economically producible resources of tight gas and shale gas. As in the United States, fracture stimulation of oil and gas wells has been common since long before the current interest in shale gas production. In Western Australia almost 800 wells have been stimulated by hydraulic fracturing since 1958, including several in the Perth Basin in 2011 and 2012  as part of shale gas exploration efforts there. The Canning Basin has received less attention to date, as it is more remote and will require greater infrastructure investment to bring producible resources, if any, to market. On the other hand, shale gas development in Australia is most active in the Cooper Basin, which lies mainly in the state of South Australia and closer to existing oil and gas infrastructure and to Australia's demand centers.
Both Japan and South Korea have limited natural gas resources and, consequently, very limited current and future production. Both countries receive the vast majority of their natural gas supplies in the form of imported LNG. In 2010, natural gas production in Japan and South Korea accounted for only 4 percent and 2 percent of their natural gas consumption, respectively. The presence of substantial deposits of methane hydrates in both Japan and South Korea has been confirmed, and both countries are investigating how those resources could be safely and economically developed. However, the IEO2013 Reference case does not include methane hydrate resources in its estimates of natural gas resources, and the widespread development of hydrates on a commercial scale is not anticipated during the projection period.
Four major natural gas producers in the Middle East—Qatar, Iran, Saudi Arabia, and the United Arab Emirates—together accounted for 85 percent of the natural gas produced in the Middle East in 2010. With more than 40 percent of the world's proved natural gas reserves, the Middle East accounts for 21 percent of the total increase in world natural gas production in the IEO2013 Reference case, growing from 15.9 trillion cubic feet in 2010 to 31.5 trillion cubic feet in 2040 (Figure 54).
The strongest growth among Middle East producers from 2010 to 2040 in the Reference case comes from Iran, where natural gas production increases by 5.4 trillion cubic feet, followed by Qatar (4.9 trillion cubic feet of new production) and Saudi Arabia (2.3 trillion cubic feet). Although Iraq is the region's fastest-growing supplier of natural gas, with average increases of 11.6 percent per year over the projection, it remains a relatively minor contributor to regional natural gas supplies. In 2040, Iraq's natural gas production totals 1.2 trillion cubic feet, or about 4 percent of the Middle East total.
Iran has the world's second-largest reserves of natural gas, after Russia, and is currently the Middle East's largest natural gas producer. Iran is also the Middle East's largest user of reinjected natural gas for enhanced oil recovery operations. In 2010 Iran reinjected more than 1 trillion cubic feet of natural gas, or 15 percent of its gross production, and in 2020 it is projected to use 3.7 trillion to 7.3 trillion cubic feet of natural gas per year for reinjection . The higher estimate is almost equal to the total for Iran's marketed natural gas production in 2020 in the IEO2013 Reference case. The actual figure for reinjection use, whatever it turns out to be, will have a significant impact on Iran's marketed natural gas production in the future.
Natural gas production in Saudi Arabia grows by an average of 1.9 percent per year, from 3.1 trillion cubic feet in 2010 to 5.4 trillion cubic feet in 2040. The Saudi Arabian national oil company, Saudi Aramco, has made several natural gas finds in the Persian Gulf that are not associated with oil fields. Three gas fields, the Karan, Arabiyah, and Hasbah, are expected to begin producing in the next 5 years, adding at least 1.3 trillion cubic feet of production when fully operational. Both Arabiyah and Hasbah are offshore, and both are sour natural gas fields,25 making them relatively expensive to produce, especially in the context of low domestic natural gas prices set by the government . The IEO2013 Reference case assumes that Saudi Arabia's policy of reserving natural gas production for domestic use will persist throughout the projection period, and that no natural gas will be exported. Thus, in the long term, production is more dependent on domestic demand growth and domestic prices than on resource availability.
Non- OECD Europe and Eurasia
In the IEO2013 Reference case, almost one-quarter of the global increase in natural gas production comes from non-OECD Europe and Eurasia, which includes Russia, Central Asia, and non-OECD Europe. Natural gas production in the region as a whole increases from 26.7 trillion cubic feet in 2010 to 45.6 trillion cubic feet in 2040 (Figure 55). Russia remains the dominant natural gas producer, accounting for more than 70 percent of the region's production throughout the projection.
In 2010, Russia produced 20.9 trillion cubic feet of natural gas, following a 10-percent drop in production in 2009 when the global economic downturn reduced demand in Russia and in its natural gas export markets. In 2010, however, the country's production recovered most of the volume lost in 2009. In the IEO2013 Reference case, Russia's natural gas production grows on average by 1.6 percent per year from 2010 to 2040, as domestic consumption and exports to both Europe and Asia continue to grow. If Russia is to increase its natural gas production, it must invest in new fields. Moreover, it will require significant investment simply to maintain current production levels, because production from its three largest natural gas fields (Yamburg, Urengoy, and Medvezh'ye) is declining . The giant Koykta field in eastern Siberia, estimated to hold 70 trillion cubic feet of natural gas and to be capable of producing 1.6 trillion cubic feet per year, is a likely candidate as a source for pipeline exports to China. Ownership of the field changed hands in early 2011, when it was bought by the Russian state firm, Gazprom . There had been little progress on exporting natural gas from the field under the previous joint venture owners, TNK-BP.
The Yamal Peninsula is another major area for future Russian production growth. The Bovanenkovo field, which is owned by Gazprom, is estimated to hold more than 170 trillion cubic feet of recoverable natural gas. Production facilities for the field were first commissioned in October 2012, with the production from the field expected to come on line over the course of several years and grow to more than 4 trillion cubic feet per year in 2017 . The Tambeiskoye field, which is majority-owned by Russia's largest independent natural gas producer, Novatek, lies to the northeast of Bovanenkovo. The field has estimated reserves of 44 trillion cubic feet, and Novatek has proposed building an LNG liquefaction facility with the capacity to export 0.7 trillion cubic feet of natural gas production per year . Finally, there is the Shtokman field in the Barents Sea, which is envisioned to produce 2.5 trillion cubic feet of natural gas annually . However, in 2012, with project costs and changes in the European natural gas market making the project uncertain, Statoil pulled out of a partnership with Gazprom to develop the field .
Natural gas production in Central Asia (which includes the former Soviet Republics) grows by 2.8 percent per year on average, from 4.6 trillion cubic feet in 2010 to 10.7 trillion cubic feet in 2040. Much of the growth is expected to come from Turkmenistan, which is already a major producer and accounted for 35 percent of the region's total production in 2010. Turkmenistan is just beginning to develop its recently reassessed giant South Yolotan-Osman field. It will be developed in several phases, with each of the initial four phases adding around 0.4 trillion cubic feet of annual natural gas production. First production from the field is expected before the end of 2013, with much of the production likely to be exported by pipeline to China. Also contributing to Central Asia's production growth is Azerbaijan, which has been planning to bring on line the second phase of natural gas production at its Shah Deniz field. Upon reaching peak production, Shah Deniz will add around 0.6 trillion cubic feet to the country's annual production.
Natural gas production in Africa grows from 7.4 trillion cubic feet in 2010 to 9.3 trillion cubic feet in 2020 and 13.6 trillion cubic feet in 2040 (Figure 56). In 2010, 79 percent of Africa's natural gas was produced in North Africa, mainly in Algeria, Egypt, and Libya. West Africa accounted for another 19 percent of the 2010 total, and the rest of Africa accounted for just 2 percent. Remaining resources are more promising in West Africa than in North Africa, which has been producing large volumes of natural gas over a much longer period. Indeed, production growth in West Africa is even faster, with annual increases over the projection period averaging 4.5 percent, compared with an average of 0.8 percent per year in North Africa.
Nigeria is the predominant natural gas producer in West Africa, although there also have been recent production increases from Equatorial Guinea, which brought an LNG liquefaction facility on line in 2007. Angola also is expected to add to West Africa's production in the near term, with its first LNG liquefaction facility expected to come on line in 2013.
In Nigeria, security concerns and uncertainty over terms of access further delay proposed export projects and limit mid-term production growth. In the IEO2013 Reference case, export projects in Nigeria regain their former momentum later in the projection period, raising production for the West Africa region to 5.2 trillion cubic feet in 2040. West Africa's share of total African natural gas production doubles from 19 percent in 2010 to 38 percent in 2040.
In 2010, East Africa produced just 0.1 trillion cubic feet of natural gas. Over the last few years, however, several new natural gas discoveries have been made in the Rovuma Basin off the coast of Mozambique and Tanzania. Anadarko Petroleum began exploration of the Rovuma Basin in 2006, and several other companies have since invested and made discoveries in the area as well. Recent offshore discoveries in Mozambique and Tanzania hold an estimated 85 trillion cubic feet and 18 trillion cubic feet of recoverable natural gas resources, respectively. In order to commercialize the resources, Anadarko and another company, Eni, have proposed separate LNG liquefaction facilities for Mozambique. In addition, BG and Statoil are discussing the possibility of a joint facility in Tanzania. The Anadarko proposal, which currently is the most advanced, is for a facility capable of exporting 0.5 trillion cubic feet per year initially, with room to increase the capacity to a total of 1.4 trillion cubic feet if more natural gas becomes available for the project .
Natural gas production in non-OECD Asia increases by 9.7 trillion cubic feet from 2010 to 2040 in the IEO2013 Reference case, with China accounting for 70 percent of the growth and India 12 percent (Figure 57). From 2010 to 2040, China has the largest increase in natural gas production in non-OECD Asia, from 3.3 trillion cubic feet in 2010 to 10.1 trillion cubic feet in 2040, for an average annual increase of 3.8 percent. Much of the increase in the later years comes from tight gas, shale gas, and coalbed methane reservoirs (Figure 58). China already is producing small volumes of coalbed methane and significant volumes of tight gas. However, the actual volumes of tight gas are unknown, as China does not report it separately. China is trying to encourage the development of coalbed methane resources. Toward that goal, it has been offering producers a subsidy of roughly $1 per million Btu since 2008 and may increase it to just over $3 per million Btu . In addition, there has been great interest in China's potential for shale gas production. China held its first auction for shale gas exploration blocks in June 2011, awarding contracts for four blocks, and in December 2012 it awarded another 19 shale gas blocks in a second auction . In addition, China is considering offering a subsidy of around $2 per million Btu for shale gas produced before 2015 .
Natural gas production in India grows at an average annual rate of 1.6 percent over the projection period, from 1.8 trillion cubic feet in 2010 to 3.0 trillion cubic feet in 2040. Production at the Dhirubhai-6 block in the Krishna Godavari Basin began in April 2009 and was a major factor in increasing India's natural gas production by more than 60 percent between 2008 and 2010. However, India faces several production challenges. A large portion of its current production comes from aging western offshore fields; production from the Krishna Godavari Basin has failed to meet earlier expectations for volumes ; and while India has been encouraging exploration of potential coalbed methane deposits, initial results have been discouraging and actual production is likely to fall short of the government estimate of 0.1 trillion cubic feet by 2013-2014 . India does have several basins that are prospective for shale gas, and in the later years of the IEO2013 Reference case production from shale resources makes a significant contribution to India's total natural gas production. According to most of the early estimates India's shale resources are much smaller than those in China or North America, and India appears to be progressing toward their development much more slowly .
Outside China and India, non-OECD Asian natural gas production grows at a relatively modest average annual rate of 0.6 percent. The two largest producers in the region, Malaysia and Indonesia, both face declining production from many older fields and must make substantial investments to maintain current production levels. While other countries are looking toward potential shale gas resources to underpin future production growth, Indonesia is focusing on its coalbed methane resources. As of late 2012, Indonesia had awarded 50 production-sharing contracts for coalbed methane areas . The sector has attracted investment from a variety of companies, including large international oil and natural gas companies, smaller regional companies, and local Indonesian companies. At least three projects are expected to be producing commercial volumes in 2013. In 2011, the Indonesian firm Medco Energi signed an agreement to sell small volumes of coalbed methane from its Sekayu development to a local power generator beginning in 2012 . Dart Energy, an Australia-based company that specializes in coalbed methane, expects to make the first sales of natural gas from its Sangatta project in 2013 . Vico Indonesia, a BP-Eni joint venture, also expects first sales of natural gas from its Sanga-Sanga project in 2013, although first production from the project began in 2011 .
Central and South America
Natural gas production in the non-OECD economies of Central and South America nearly doubles from 2010 to 2040, from 5.4 trillion cubic feet to 10.4 trillion cubic feet (Figure 59). Brazil's production increases more than sixfold, from 0.4 trillion cubic feet in 2010 to 2.8 trillion cubic feet in 2040, at an average annual growth rate of 6.3 percent that is more than double the next highest rate for the region (except for Central America and the Caribbean, where production levels are so low that the growth rate is immaterial). As a result, Brazil's share of regional production grows from 8 percent in 2010 to nearly 27 percent in 2040.
Just over one-fifth (21 percent) of Brazil's natural gas production growth from 2010 to 2040 comes from tight gas, shale gas, or coalbed
methane production. Recent discoveries of oil and natural gas in the pre-salt Santos Basin are expected to increase the country's
natural gas production, particularly in the Tupi field, which could contain between 5 trillion and 7 trillion cubic feet of recoverable
natural gas. Much of Brazil's natural gas production occurs in the offshore fields of the Campos Basin in Rio de Janeiro state. Although
infrastructure bottlenecks in the past have hindered the transport of natural gas from those fields to the country's 4,000-mile pipeline
network, Petrobras has now completed the 870-mile Southeast Northeast Interconnection Gas Pipeline (GASENE), connecting
southeastern offshore supply with fields in the northeast. In addition, Brazil has recently built two new LNG terminals—the Pecem
terminal in the northeast and the Guanabara Bay terminal in the southeast—with a combined sendout capacity of 740 million cubic feet per day, and plans to build a third terminal with 495 million cubic feet per day of capacity in Bahia state this year .
Despite recent declines in production, countries in the Southern Cone (mainly Argentina)26 become the region's leading natural
gas producers by 2040. In the IEO2013 Reference case, annual production in the Southern Cone increases by 150 percent, from
1.4 trillion cubic feet in 2010 to 3.5 trillion cubic feet in 2040—enough for the Southern Cone to surpass northern producers in
terms of total volume. Although the increase in the Southern
Cone's natural gas production, averaging 3.0 percent per year
from 2010 to 2040, is less than half the 6.3-percent average
annual increase in Brazil, it is sufficient for the region's annual
production to remain 0.7 trillion cubic feet above Brazil's
in 2040. Almost all (93 percent) of the Southern Cone's
production increase comes from tight gas, shale gas, or coalbed methane gas fields.
Argentina is leading the non-OECD Americas region in its pursuit of tight gas and shale gas. Much of the interest in tight and shale gas can be attributed to an announcement in November 2012 that the government would allow the ceiling on natural gas wellhead prices to rise to $7.50 per million Btu . Argentina already is producing natural gas from the Vaca Muerta shale formation in the country's western NeuquÃ©n Basin, which is estimated to contain more than one-half of Argentina's 774 trillion cubic feet of recoverable shale gas resources .
Growth in natural gas production in Brazil and the Southern Cone will increase overall natural gas production for the non-OECD Central and South America region. However, production from the Northern Producers region (primarily Colombia, Venezuela, and Trinidad and Tobago) grows at an average annual rate of only 0.5 percent (the region's second-lowest rate after the Andean countries). Although Venezuela's 195 trillion cubic feet of proven natural gas reserves are the Western Hemisphere's second largest after the United States, only an estimated 10 percent of its natural gas production is not associated with oil fields. The state oil company, Petróleos de Venezuela, S.A., has limited experience in developing nonassociated natural gas fields, and international partners will be needed for production to move forward in a meaningful way . The result is that, while the Northern Producers provided 51 percent of all natural gas output in the non-OECD Central and South American region in 2010, their share falls to 30 percent in 2040. Almost all of their production comes from fields that do not include tight gas, shale gas, or coalbed methane resources. Production from those more traditional gas fields in the Northern Producers region increases by an average of 0.2 percent per year from 2010 to 2040.
World natural gas trade
International trade in natural gas is undergoing rapid transformation. Global LNG trade more than doubled from just under 5 trillion cubic feet in 2000 to just over 10 trillion cubic feet in 2010, and the subsequent 5-year period may be no less dynamic. Although little new liquefaction capacity is planned to come on line globally between 2010 and 2015, world LNG flows adjusted quickly in 2011 and 2012 to accommodate a surge in Japan's demand for LNG in the wake of the Fukushima disaster, and to account for underutilization of LNG liquefaction capacity in North Africa and Southeast Asia. Global LNG markets already have shown greater flexibility in dealing with such issues than they did during past disruptions of supply or demand. Another surge in LNG trade may be coming in the 2015-2025 timeframe, as several projects currently under construction in Australia are expected to be on line before 2020, and several projects in various stages of development in North America are planned to be on line soon after the Australian projects (Table 8).
Although LNG trade has grown considerably faster in recent years, flows of natural gas by pipeline still account for most of world natural gas trade in the IEO2013 Reference case, which includes several new long-distance pipelines and expansions of existing infrastructure through 2040. The largest volumes of internationally traded natural gas by pipeline currently are in North America (between Canada and the United States) and in Europe (among numerous OECD and non-OECD countries). By the end of the projection period, the IEO2013 Reference case includes large volumes of pipeline flows into China from both Russia and Central Asia.
Increased LNG trade and cross-border natural gas pipeline flows have long indicated transformation of markets around the world, including increased natural gas consumption in growing economies and changes in interregional pricing practices. Although the emergence of a global natural gas market has yet to occur with a depth rivaling other global commodities such as oil, an evolution toward greater interregional trade and pricing continues.
Interest in developing tight gas, shale gas, and coalbed methane resources has grown significantly. The results are already noticeable in North America, where the current development of shale resources has reduced the demand for imports. It is likely that significant shale resources also exist in other large consuming countries, including China and several European nations. Although development of shale resources in China and other countries could slow the growth of their demand for imports, exploitation of tight gas, shale gas, and coalbed methane resources is not necessarily a countervailing force to growing international trade. For example, many of the previously mentioned LNG liquefaction projects under construction in Australia are to be supplied by production from coalbed methane resources. Additionally, all the LNG export projects proposed in North America are either directly or indirectly based on growing production from tight gas and shale gas reservoirs.
OECD natural gas trade
In 2010, about one-quarter of natural gas demand in the OECD nations was met by net imports from non-OECD countries. That share falls to around 20 percent in 2040, when the total volume of net imports to OECD countries is about the same as in 2010, even as significant differences in the trade profiles within the OECD evolve. Both imports and exports from different OECD regions grow substantially over the projection period. In the mid-term, OECD imports increase, with growing demand for imports to Europe, Japan, and South Korea dominating the total. Later in the projection, however, growing exports from Australia and North America reverse the trend. In the IEO2013 Reference case, OECD net imports grow by 1.3 percent per year on average from 2010 to 2020, peaking before 2020. For the remainder of the projection, OECD net imports as a whole decline by 0.3 percent per year, with 2040 net imports less than 10 percent higher than in 2010.
Regional net imports among the nations of the OECD Americas begin a downward trend after 2010 that extends through 2040 in the IEO2013 Reference case (Figure 60). In the United States, rising domestic production reduces the need for imports, primarily as a result of robust growth in regional production of shale gas. The United States becomes a net exporter of natural gas in 2020, with net exports growing to 3.6 trillion cubic feet in 2040. Most of the growth in U.S. net exports can be attributed to pipeline exports to Mexico, which grow steadily over the projection period, as increasing volumes of natural gas imported from the United States fill the growing gap between Mexico's production and consumption. U.S. exports to Mexico increase from 0.3 trillion cubic feet in 2010 to 2.4 trillion cubic feet in 2040.
U.S. domestically sourced exports of LNG, excluding exports from the existing Kenai facility in Alaska, begin in 2016 and grow to 1.6 trillion cubic feet per year in 2027, with one-half of U.S. LNG exports originating in the Lower 48 states. The other half of the U.S. LNG exports originate from Alaska. Continued low levels of LNG imports through the projection period position the United States as a net exporter of LNG by 2016. However, future U.S. exports of LNG depend on a number of factors that are difficult to anticipate and thus are highly uncertain.
From 2000 to 2010, Canadian pipeline exports declined by more than 25 percent, as growing shale gas production in the United States reduced the need for imports of natural gas from Canada. In the IEO2013 Reference case, pipeline exports from Canada continue to decline (Figure 61). However, Canada becomes a net exporter of LNG before 2020, and LNG export volumes begin to replace some of the lost pipeline export volumes. Currently, there are four LNG export facilities proposed for Canada's west coast. The exports are targeted to Asian markets, and a variety of Asian companies have signed contracts to buy LNG, invested in the liquefaction projects, or invested in the development of tight gas and shale gas resources to supply the liquefaction projects. At end of the projection in 2040, Canada's total net natural gas exports are less than 10 percent higher than they were in 2010.
In the OECD Americas as a whole, the growing import dependence of Mexico and Chile partially offsets the growing exports from the United States and Canada. As Mexico's domestic production fails to keep pace with demand growth, its net imports increase from 0.5 trillion cubic feet in 2010 to 1.6 trillion cubic feet in 2020 and 3.0 trillion cubic feet in 2040. Pipeline flows from the United States, which currently account for about 16 percent of Mexico's natural gas supply, increase substantially in the projection. LNG imports, which accounted for 9 percent of Mexican natural gas supply in 2010, also grow, but more moderately.
Natural gas production in Chile is limited, and significant imports are required to meet the country's demand. In the past, Chile relied on imports from Argentina for a large portion of its total supply. However, natural gas imports from Argentina to Chile peaked in 2004 at 254 billion cubic feet, or 87 percent of Chile's total natural gas supply. Subsequently, the Argentine government enacted price controls that had the dual effect of encouraging demand for natural gas and discouraging investment in exploration and production. As a result, Argentina limited the supply of natural gas available for export in order to meet domestic demand. Natural gas imports and consumption in Chile fell as demand went unmet. Chile has since moved to ensure that it will be able to receive natural gas from a wider variety of sources by opening two LNG regasification terminals in 2009 and 2010, one in Quintero near Santiago and one in the northern town of Mejillones .
In OECD Europe, total natural gas imports continue to grow over the course of the projection, by an average of 1.6 percent per year from 2010 to 2040 as local production sources decline, especially in the United Kingdom. Pipeline imports of natural gas to OECD Europe peaked in 2007 and 2008, when they accounted for 37 percent of OECD Europe's total supply. Since the onset of the financial crisis in late 2008, which resulted in lower natural gas demand and excess supplies worldwide, buyers generally have preferred to buy larger volumes of LNG or other uncontracted natural gas on spot markets rather than opting for supplies tied to more expensive contracts linked to world oil prices (see "Natural gas pricing mechanisms around the world"). In 2009 and 2010, the pipeline share of OECD Europe's total natural gas supply declined to 34 percent, while the LNG share grew to 13 percent in 2010. In the IEO2013 Reference case, the pipeline share of OECD Europe's natural gas imports grows to between 40 and 50 percent of total natural gas supply. LNG imports grow to around 20 percent of supply and maintain that share through 2040.
The recent increase in LNG supplies to OECD Europe, and particularly to the United Kingdom, has added complexity to natural gas pricing in the region. In comparison to long-term contracts with prices linked to oil and petroleum product prices, LNG supplies have improved the prospects for spot market trading. Continental Europe's long-term contracts with suppliers of pipeline gas, which include Russia, Algeria, and Norway, among others, have some flexibility in terms of volumes, but the prices generally are linked to lagged prices for oil products. Although some suppliers, such as Norway, switched as much as 30 percent of their contracted volumes to spot market pricing, other countries, such as Algeria, altered their pricing far less or not at all . The subsequent loss of market share by pipeline suppliers to OECD Europe with less flexibility in pricing since 2008 may indicate eventual changes in the pricing of pipeline imports from a variety of countries—including Russia, which is by far the largest exporter to Europe. However, the extent of such changes over the long term remains to be seen.
The world's two largest LNG importers, Japan and South Korea, are in OECD Asia. The Australia/New Zealand country grouping, also in OECD Asia, is on its way to becoming the world's second largest exporter of LNG (after Qatar). With Australia's export growth dominating the region as a whole in the long-term projection, OECD Asia's net demand for imports declines from 4.6 trillion cubic feet in 2010 to 3.1 trillion cubic feet in 2040 (Figure 62).
Japan and South Korea continue to be major players in world trade of LNG, despite consuming relatively small amounts of natural gas on a global scale. Combined, their natural gas consumption represented slightly less than 5 percent of world consumption in 2010. At the same time, however, it represented almost 50 percent of total global LNG imports. Because the two countries are almost entirely dependent on LNG imports for natural gas supplies, overall consumption patterns are translated directly into import requirements. South Korea's imports grow moderately over the projection period, in line with moderate growth of natural gas demand.
Japan has experienced dramatic growth in LNG imports since the Fukushima nuclear disaster in early 2011. LNG imports in 2012 were approximately 25 percent higher than in 2010 . In the IEO2013 Reference case, much of Japan's nuclear capacity is assumed to come back on line gradually, reducing the need for LNG imports. After nuclear capacities have stabilized, Japanese import demand resumes its previous slow growth, based on relatively slow economic and population growth and slow growth in natural gas demand. There is however, considerable uncertainty in any projection of how much nuclear capacity Japan is likely to bring back on line and when (see nuclear section of the Electricity chapter).
Australia is by far the largest and most active LNG exporter among the OECD countries and remains so throughout the projection. In 2010, Australia exported just under 1 trillion cubic feet of natural gas from its two LNG export facilities that were operating at the time. Both North West Shelf LNG and Darwin LNG are located in the northwest part of the continent, an area rich in natural gas resources that is targeted for substantial development in coming years. A third liquefaction facility, Woodside's Pluto LNG, began exporting LNG in 2012.
Seven other independent liquefaction projects have been sanctioned in Australia over the past few years (Table 8), beginning in 2009 with Chevron's Gorgon LNG, the largest of the projects at 0.7 trillion cubic feet. Including Gorgon LNG, four of the seven sanctioned projects will utilize gas from reservoirs offshore northwest Australia. The three remaining LNG export projects are situated in eastern Australia and will export gas from coalbed methane reservoirs. In total, the seven sanctioned projects have a planned export capacity of 2.8 trillion cubic feet, all of which is scheduled to come on line before 2020. In the IEO2013 Reference case, Australia's exports of natural gas more than quintuple from 2010 to 2040, with exports totaling 4.6 trillion cubic feet in 2040.
Non-OECD natural gas trade
Net exports of natural gas from the non-OECD countries grow by less than 1.0 percent per year on average in the IEO2013 Reference case. As with the OECD countries, the slow growth on the whole masks the dynamism of trade in the separate non-OECD regions and countries. Non-OECD Europe and Eurasia accounts for more than 30 percent of the total global increase in interregional natural gas exports, and non-OECD Asia accounts for around 50 percent of the total global increase in interregional natural gas imports. The vast natural gas resource base in non-OECD countries points to their continued ability to meet incremental growth in demand for natural gas both among countries in the region and among the OECD countries. However, with demand in non-OECD countries (excluding non-OECD Europe and Eurasia) rising rapidly in the projection, non-OECD countries export progressively less of their overall production to OECD countries over time. The share of non-OECD production that is exported peaks before 2020 at around 20 percent, before declining to 13 percent in 2040.
Non-OECD Europe and Eurasia
Net exports of natural gas from Russia, the largest exporter in the world, are the most significant factor in exports from non-OECD Europe and Eurasia. Net exports from non-OECD Europe and Eurasia rise from 5.5 trillion cubic feet in 2010 to 8.2 trillion cubic feet in 2020 and 15.3 trillion cubic feet in 2040, at an average annual rate of 3.5 percent (Figure 63). Russia provides the largest incremental volume to meet the increase in demand for supplies from non-OECD Europe and Eurasia, with its net exports growing by an average of 2.4 percent per year, from 6.6 trillion cubic feet in 2010 to 13.5 trillion cubic feet in 2040. LNG and pipeline exports from Russia to customers in both Europe and Asia increase throughout the projection.
Despite recent declines in demand for natural gas in Europe, Russia has recently completed a massive new pipeline project. The Nord Stream pipeline consists of two parallel lines under the Baltic Sea to Germany. The first line was commissioned in November 2011, with the second line following about a year later. The Nord Stream pipeline has a total flow capacity of 1.9 trillion cubic feet of natural gas per year, or just over 10 percent of OECD Europe's total natural gas consumption in 2010. Flows through the Nord Stream pipeline are expected to be significant, in part because the pipeline route bypasses eastern European transit states with which Russia has had pricing and payment disputes in the past. The IEO2013 Reference case also incorporates pipeline flows from Russia to China.
Exports from Central Asia could add substantial supplies to markets in both the East and the West. In late 2009, flows of natural gas to China from Turkmenistan began with the completion of a pipeline running from the Bagtyyarlyk, Saman-Depe, and Altyn Asyr fields in Turkmenistan through Uzbekistan and Kazakhstan and eventually connecting to China's second West-East pipeline in Xinjiang province . In 2012, China received imports from Uzbekistan for the first time, in addition to flows on the same pipeline from Turkmenistan. Chinese imports via pipeline from Central Asia in 2012 totaled approximately 0.7 trillion cubic feet . Turkmenistan also exports natural gas to Russia via pipeline, and Azerbaijan exports natural gas to Turkey. In the IEO2013 Reference case, exports from Central Asia grow from 1.5 trillion cubic feet in 2010 to 5.7 trillion cubic feet in 2040, with increases averaging 4.6 percent per year.
Net exports of natural gas from the Middle East grow at an annual rate of 3.0 percent, as flows from the region increase from 2.7 trillion cubic feet in 2010 to 6.7 trillion cubic feet in 2040 (Figure 64). An important factor in the increase, particularly with regard to brisk growth in volumes in the near term, is the rise of LNG supplies from Qatar, which went -20 from exporting its first LNG in 1999 to being the largest LNG exporter in the world in 2009. Qatar's LNG exports continue to increase through 2040. Its total LNG export capacity reached 77 million tons (3.6 trillion cubic feet) per year in early 2011 with the completion of the last in a line of six large-volume liquefaction trains under construction since 2008. Each train has the capacity to produce the equivalent of 360 billion cubic feet of natural gas per year for export .
Qatar's natural gas exports grow by an average of 10.7 percent per year from 2010 to 2015 in the Reference case, then slow to an average increase of 1.1 percent per year after 2015. Because of a current moratorium on further development from the North Field, no new LNG projects are being initiated. Qatar enacted the moratorium in 2005 in order to assess the effect of the ongoing increase in production on the North Field before committing to further production increases . If Qatar decides to lift the moratorium on North Field development in 2014, its stated development priority is to ensure that it can meet long-term domestic natural gas needs for power generation, water desalination, and local industry. Only after those needs are met will it consider further increases in exports, and any increases are expected to come primarily from optimization of current facilities.
Despite possessing the second-largest reserves of natural gas in the world, Iran continues to struggle with the formation of an
export program that will result in significant commercialization of its resources. The country shares the North Field/South Pars
Field with Qatar and has many export projects under consideration through the development of its portion of those reserves.
Nonetheless, the country as of 2010 was just barely a net exporter, delivering slightly higher volumes of natural gas to Turkey than it received from Turkmenistan (resulting in net exports of 0.1 trillion cubic feet). Although its first LNG export plant is under construction, Iran is without international partners and without an obvious source for obtaining liquefaction technology. Other export projects continue to be discussed, but as a result of international sanctions and internal politics there has been little progress on most projects. The IEO2013 Reference case shows moderate flows from Iran, so that by 2040 the country is a net exporter of 1.6 trillion cubic feet per year.
Elsewhere in the Middle East, Yemen, Oman, and Abu Dhabi in the United Arab Emirates (UAE) also currently export LNG, although the potential for growth in exports from those and other countries in the Middle East appears to be limited by the growth of their domestic demand. Significant volumes of LNG have been imported by Kuwait and also by Dubai in the UAE, which completed construction of an LNG import facility in November 2010 and received its first cargo a month later . Both Oman and the UAE also are currently importing natural gas via pipeline from Qatar. The IEO2013 Reference case projects a similar trend for smaller producers in the Arabian Peninsula region as a whole, including Kuwait, Oman, the UAE, and Yemen. As a group they exported less than 0.2 trillion cubic feet of natural gas on a net basis in 2010, and the volume of their net imports rises throughout the projection to a total of 1.3 trillion cubic feet in 2040.
Net exports of natural gas from Africa increase in the projection at a rate of 0.9 percent per year (Figure 65). In 2010, the region's net exports totaled about 3.8 trillion cubic feet, led by net exports of 2.8 trillion cubic feet from North Africa. Between one-half and two-thirds of the exports from North Africa are delivered by pipeline from Algeria, Egypt, and Libya to Spain, Italy, and parts of the Middle East. The remainder is exported as LNG throughout the world, primarily to European countries, from liquefaction facilities in Algeria, Egypt, and Libya.
Recent political events in North Africa have significantly affected natural gas exports. Flows from Libya to Italy on the Greenstream pipeline were halted in March 2011 but resumed before the end of the year, with volumes gradually increasing toward earlier levels. Even before the political unrest in 2011, utilization rates were low at Egypt's two LNG export facilities, largely due to the prioritization of domestic consumption over exports. Exports from Egypt have declined further since 2011, as the natural gas pipelines from Egypt to Israel, Jordan, and Syria have been sabotaged repeatedly, effectively halting those flows.
In the IEO2013 Reference case, net exports from both West Africa and East Africa grow at a robust average annual rate of 4.5 percent from 2010 to 2040, although starting from very different levels. For both regions, much of the growth comes in the later part of the projection. Security concerns and uncertainty over terms of access in Nigeria have significantly delayed any progress on currently proposed LNG export projects. East Africa also faces significant above-ground challenges, simply because recent production and export proposals represent a large change in scale of operations for the oil and gas industries in Mozambique and Tanzania, where physical and regulatory infrastructures are not yet in place to support large-scale production and export of natural gas.
Non-OECD Asia is the only regional grouping that changes from a net exporter to a net importer of natural gas in the IEO2013 Reference case. With net imports of 12.1 trillion cubic feet in 2040, the region becomes the world's second-largest importing region, behind only OECD Europe. China has the largest increase in import demand, requiring imports of 7.7 trillion cubic feet per year—more than 40 percent of its annual natural gas consumption—in 2040 (Figure 66).
Non-OECD Europe and Eurasia
To meet its future demand, China is actively pursuing multiple potential sources for natural gas imports. China is currently receiving LNG from four different countries under long-term contracts, with additional spot purchases occasionally coming from other countries. Chinese companies also have signed contracts to begin or increase imports from Papua New Guinea, Australia, Qatar, and Malaysia and are taking equity stakes in liquefaction projects around the world. PetroChina holds a 20-percent interest in the LNG Canada project led by Shell, which plans to export 0.6 trillion cubic feet of LNG per year from Canada's west coast.
China is also pursuing multiple sources for pipeline natural gas imports. The country's first natural gas import pipeline, completed in late 2009, transports supplies from Turkmenistan and Uzbekistan. China also has an agreement in place with Kazakhstan to begin importing natural gas in the future. Another new pipeline from Myanmar, scheduled for completion in 2013, will carry 0.4 trillion cubic feet of natural gas per year from Myanmar's offshore fields in the Bay of Bengal to Kunming in China's Yunnan province . In addition, China and Russia continue to discuss future natural gas pipeline connections between the two countries. In 2009, the two countries reached an agreement that envisions two separate large-diameter pipelines from eastern and western Siberia by 2014 or 2015. The 2009 agreement suggested that volumes of 2.5 to 2.8 trillion cubic feet of natural gas per year would be exported through the proposed pipelines, although the countries have yet to agree on a price for the natural gas.
India's imports as a share of its total natural gas consumption grow to around 40 percent before declining in the later years of the Reference case projection, when production from shale resources starts to reverse the trend. In 2010, import growth remained muted, with LNG deliveries accounting for about 19 percent of overall supplies while new production from the Krishna Godavari Basin was brought on line . Over the long term, as its domestic production fails to keep up with demand, India's import requirements increase. Its imports total 1.2 trillion cubic feet in 2040 in the Reference case. Accordingly, India continues to expand its LNG import infrastructure. At the beginning of 2013 there were two fully operational LNG terminals in India, and its new Kochi terminal is expected to be on line before the end of 2013. The Dabhol import facility is operational, but it can operate for only 6 months of the year until a breakwater is built . Numerous other facilities have been proposed, but progress has been slow as industry participants have chosen first to evaluate the production potential from the Krishna Godavari Basin.
Non-OECD Central and South America
Natural gas trade in non-OECD Central and South America
has become increasingly globalized, as several countries have
become involved in the LNG trade. New LNG regasification
capacity facilitates growth in the region's gross imports of natural gas through 2040, but the discovery of large new natural gas reserves throughout the region increases its gross exports by a
greater amount. As a result, the region's overall net exports nearly triple, from 0.5 trillion cubic feet in 2010 to 1.4 trillion cubic feet in 2040 (Figure 67), an average annual increase of 3.3 percent.
LNG regasification facilities in Brazil and the Southern Cone (excluding Chile, an OECD member state since 2010) have received LNG supplies fairly consistently over the past three years. In 2010, combined net imports for Brazil and the Southern Cone totaled 0.6 trillion cubic feet. Brazil currently receives LNG shipments—primarily from Trinidad and Tobago—at the Pecem terminal in the northeast and the Guanabrara Bay terminal in the southeast. It also receives natural gas pipeline imports via the Gasbol line, which runs from Santa Cruz, Bolivia, to Brazil's Porto Alegre and Sao Paulo . Argentina also imports most of its natural gas via pipeline from Bolivia, along with some LNG, principally from Trinidad and Tobago. The Southern Cone's LNG imports could increase with the construction of an offshore LNG terminal near Montevideo, Uruguay, in addition to a joint regasification project currently being pursued by the governments of Argentina and Venezuela and a potential third LNG terminal to be built by the governments of Argentina and Qatar . Still, the Southern Cone becomes the region's largest net exporter of natural gas by 2040, largely due to the discovery of large shale gas reserves in Argentina's northwestern Neuquén province. In addition, as a result of the discovery of large amounts of natural gas in Brazil's pre-salt Santos Basin, that country's gross export and domestic production levels grow sufficiently to make the country's natural gas trade balance essentially zero in 2040.
The first LNG export project in the Andean South America region, which includes Bolivia, Ecuador, and Peru, was completed in Pampa Melchorita, Peru, in mid-2010. In February 2012, Peru exported an estimated 15 billion cubic feet of natural gas from the terminal, according to LNG World News . Pipeline exports from Bolivia, also in the Andean region, remain more or less flatover the projection period but switch from being directed mainly toward Brazil to being directed mainly toward Argentina in the Southern Cone region. Overall net exports from the Andean region decline slightly from 2010 to 2040 at an average annual rate of 0.8 percent, and net exports from the Northern Producers fall by an average of 1.7 percent per year, from 0.7 trillion cubic feet in 2010 to 0.4 cubic feet in 2040. In Venezuela, projects that are expected to make more of the associated natural gas produced from its oil fields available for domestic consumption include the Interconnection Centro Occidente (ICO) system, which is designed to transport 520 million cubic feet per day of natural gas between the eastern and western parts of the country. In addition, the Antonio Ricaurte pipeline, which connects Colombia with Venezuela, allows Colombia to export natural gas to Venezuela, with contracted volumes ranging between 80 and 150 million cubic feet per day. Current plans call for the flow of the pipeline to be reversed, with Venezuela exporting 140 million cubic feet per day of natural gas to Colombia .
As reported by Oil & Gas Journal , the world's proved natural gas reserves have grown by 39 percent over the past 20 years, to a total of 6,793 trillion cubic feet as of January 1, 2013 (Figure 68). Estimated proved reserves have grown particularly in non-OECD countries, by 1,915 trillion cubic feet since 1993. In contrast, proved reserves in OECD countries have decreased by 7 trillion cubic feet since 1993. As a result, the portion of proven world natural gas reserves located in OECD countries declined from 11 percent in 1993 to 8 percent in 2013.
Most of the world growth in proved natural gas reserves has taken place since 2003. Over the past 10 years, estimates of proved world natural gas reserves rose by 1,292 trillion cubic feet, at an average annual rate of 2.1 percent, as compared with 1.2 percent annually from 1993 to 2003. Estimated proved reserves in the non-OECD countries rose by 1,285 trillion cubic feet, or an average of 2.3 percent annually, over the same period, compared with 1.4 percent annually from 1993 to 2003. The most rapid increase in proved reserves in the non-OECD countries, averaging 2.8 percent per year, was from 2003 to 2008, including a massive increase from 509 to 910 trillion cubic feet in 2004 in Qatar.
As of January 1, 2013, however, almost one-half of the growth in estimates of world proved reserves was based on increases in OECD countries, where proved reserves increased by 4 percent, or 19 trillion cubic feet, from their 2012 levels. Much of that increase is accounted for by the addition of 15 trillion cubic feet of proved reserves in OECD Asian countries—a 51-percent increase from 2012. Proved reserves in the OECD Americas rose by 7 trillion cubic feet from 2012 to 2013, while proved reserves in OECD Europe declined by 3 trillion cubic feet. Estimated proved reserves in the non-OECD countries increased by 27 trillion cubic feet from 2012 to 2013, with a combined 56 trillion cubic feet of additional proved reserves in the Middle East, China, and non-OECD Europe and Eurasia partially offset by a decrease of 33 trillion cubic feet in Indonesia's proved reserves.
Estimates of global proved reserves were nearly flat from 2012 to 2013, growing by only 47 trillion cubic feet (less than 1 percent). The largest change to proved natural gas reserve estimates was for Iran, which has the world's second-largest proved natural gas reserves. Iran's estimated proved natural gas reserves increased by 19 trillion cubic feet (2 percent), from 1,168 trillion cubic feet in 2012 to 1,187 trillion cubic feet in 2013. Estimated proved reserves in the rest of the Middle East also grew modestly, by 0.3 percent, from 1,622 trillion cubic feet in 2012 to 1,627 trillion cubic feet in 2013.
The second-largest change to estimated proved reserves was for China, where estimated proved reserves increased by 17 trillion cubic feet (16 percent), from 107 trillion cubic feet in 2012 to 124 trillion cubic feet in 2013. As a result, China's estimated proved reserves are now the world's eleventh largest, and Iraq's proved reserves have dropped to the twelfth largest. Russia's estimated proved reserves remained the world's largest at 1,688 trillion cubic feet.
Current estimates of worldwide natural gas proved reserves indicate a large resource base to support growth in markets through 2040 and beyond. Like reserves for other fossil fuels, natural gas reserves are spread unevenly around the world. Natural gas proved reserves are concentrated in Eurasia and the Middle East, where ratios of proved reserves to production suggest decades of resource availability. In the OECD countries, however, including many in which there are relatively high levels of consumption, current ratios of proved reserves to production are significantly lower. The impact of that disparity is reflected in the IEO2013 projections for increased international trade in natural gas.
Almost three-quarters of the world's proved natural gas reserves are located in the Middle East and Eurasia (Figure 69), with Russia, Iran, and Qatar together accounting for about 55 percent of world proved natural gas reserves as of January 1, 2013 (Table 9). Proved reserves in the rest of the world's regions are distributed fairly evenly. Despite high rates of increase in natural gas consumption, particularly over the past decade, most regional reserves-to-production ratios have remained high. Worldwide, the reserves-to-production ratio is estimated at 63.6 years . Central and South America has a reserves-to-production ratio of 45.2 years, Russia 73.5 years, and Africa 71.7 years. The Middle East's reserves-to-production ratio exceeds 100 years.
Proved reserves include only estimated quantities of natural gas that can be produced economically from known reservoirs, and therefore they are only a subset of the entire potential natural gas resource base. Resource base estimates include estimated quantities of both discovered and undiscovered natural gas that have the potential to be classified as reserves at some time in the future. In the Reference case, the resource base does not pose a constraint on global natural gas supply. By basing long-term production assessments on resources rather than reserves, EIA is able to present projections that are physically achievable and can be supported beyond the 2040 projection horizon. The realization of such production levels depends on future growth in world demand, taking into consideration such above-ground limitations on production as profitability and specific national regulations, among others.
- World energy demand and economic outlook
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