Natural gas

Overview

In the IEO2011 Reference case, natural gas is the world's fastest-growing fossil fuel, with consumption increasing at an average rate of 1.6 percent per year from 2008 to 2035. Growth in consumption occurs in every IEO region and is most concentrated in non-OECD countries, where demand increases nearly three times as fast as in OECD countries (Figure 40). Increases in production in the non-OECD regions more than meet their projected consumption growth, and as a result non-OECD exports to OECD countries grow through 2035. Non-OECD producers account for more than 81 percent of the total growth in world natural gas production from 2008 to 2035.

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The global recession of 2008-2009 resulted in a decline of nearly 4 percent in natural gas demand in 2009. As the recession receded and economic growth resumed, natural gas demand reached an estimated 113.1 trillion cubic feet in 2010, exceeding annual consumption levels before the economic downturn [67]. Natural gas continues to be favored as an environmentally attractive fuel relative to other hydrocarbon fuels. Natural gas consumption grows robustly in the IEO2011 Reference case, from 110.7 trillion cubic feet in 2008 to 168.7 trillion cubic feet in 2035.

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 2035, nearly three times as fast as the 0.8-percent annual growth rate projected for natural gas demand in the OECD countries. As a result, non-OECD countries account for 76 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 2008 to 59 percent in 2035.

Natural gas continues to be the fuel of choice in many regions of the world in the electric power and industrial sectors, 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, and also because of its significant price discount relative to oil in many world regions. In addition, it is an attractive alternative fuel for new power generation plants because of low capital costs and favorable thermal efficiencies. In the Reference case, total world natural gas consumption for industrial uses increases by an average of 1.7 percent per year through 2035, and consumption in the electric power sector grows by 2.0 percent per year. The industrial and electric power sectors together account for 87 percent of the total projected increase in natural gas consumption.

Contributing to the strong competitive position of natural gas among other energy sources is a strong growth outlook for reserves and supplies. Significant changes in natural gas supplies and global markets continue with the expansion of liquefied natural gas (LNG) production capacity, even as new drilling techniques and other efficiencies have made production from many shale basins economical worldwide. The net impact has been a significant increase in resource availability, which contributes to lower prices and higher consumption in the IEO2011 Reference case projection.

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The largest production increases from 2008 to 2035 (Figure 41) are projected for the Middle East (15.3 trillion cubic feet) and non-OECD Asia (11.8 trillion cubic feet). Iran and Qatar increase natural gas production by a combined 10.7 trillion cubic feet, or nearly one-fifth of the total increment in world gas production. A significant share of the increase is expected to come from a single offshore field, which is called North Field on the Qatari side and South Pars on the Iranian side.

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Although the extent of the world's unconventional natural gas resource base (which for the purposes of the IEO2011 consists of tight gas, shale gas, and coalbed methane) has not yet been assessed fully, the IEO2011 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 contributed to a near doubling of total U.S. technically recoverable natural gas resource estimates over the past decade. In the Reference case, shale gas accounts for 47 percent of U.S. natural gas production in 2035. Unconventional resources are even more important for the future of domestic natural gas supplies in Canada and China, where they account for 51 percent and 72 percent of total domestic production, respectively, in 2035 in the Reference case.

LNG accounts for a growing share of world natural gas trade in the Reference case. World natural gas liquefaction capacity nearly doubles, from about 8 trillion cubic feet in 2009 to 15 trillion cubic feet in 2035. Most of the increase in liquefaction capacity is in the Middle East and Australia, where a multitude of new liquefaction projects are expected to be developed, many of which will become operational within the next decade. Utilization of liquefaction capacity is expected to remain high over the entire projection. Given the capital-intensive nature of liquefaction projects, long-term contracts requiring the purchase of high volumes (or high "takes") often are used to ensure high utilization rates and acceptable returns on investments.

World natural gas consumption

OECD natural gas consumption

OECD Americas

Natural gas consumption in the OECD Americas increases by 0.9 percent per year in the IEO2011 Reference case, from 28.8 trillion cubic feet in 2008 to 37.1 trillion cubic feet in 2035, accounting for 60 percent of the total increase for OECD countries and 14 percent of the total increase for the world over the projection period. U.S. consumption increases by 0.5 percent per year on average (Figure 43), considerably less than the annual increases in Canada (1.5 percent) and Mexico/Chile (3.4 percent). The United States and Mexico/Chile each account for 40 percent of the growth in OECD America's natural gas consumption, with Canada accounting for the remaining 20 percent.

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In the United States, natural gas use increases by slightly more than 14 percent from 2008 to 2035, primarily as a result of growth in the price-sensitive industrial and electric utility sectors, where natural gas use increases by 1.4 and 1.2 trillion cubic feet, respectively, over the period. Absent pending environmental regulations, which were not considered in the Reference case, natural gas demand for electricity generation remains flat through about 2025, primarily because of an increase in other generation capacity with lower operating costs, such as renewable capacity and some nuclear capacity that comes on line early in the projection period with support from various incentive programs. Toward the end of the period, when additional capacity is required, the more favorable economics of natural gas—in spite of increasing natural gas prices—lead to strong growth, with natural-gas-fired capacity accounting for 82 percent of capacity additions between 2025 and 2035. In contrast, industrial natural gas consumption grows sharply in the near term and levels off after 2020. The near-term growth is a result of a strong recovery in industrial production, growth in combined heat and power generation, and relatively low natural gas prices. When natural gas prices rise toward the end of the projection, the growth in industrial natural gas use levels off.

Although the United States remains by far the largest consumer of natural gas in the OECD Americas, demand growth also is robust in the other nations of the region. For example, natural gas consumption increases by 3.4 percent per year in Mexico/Chile and by 1.5 percent per year in Canada, strongly outpacing the 0.5-percent average annual growth projected for the United States. In Canada, 66 percent of the growth in natural gas consumption is for industrial uses (including significant amounts of natural gas used in the development of Canada's vast oil sands deposits) and 29 percent is for electricity generation.

In Mexico/Chile, the strongest growth in natural gas consumption is concentrated almost exclusively in the electricity generation and industrial sectors, where consumption increases by 1.9 and 1.3 trillion cubic feet, respectively, from 2008 to 2035. Chile's natural gas consumption shrank from 302 billion cubic feet in 2005 to 93 billion cubic feet in 2008 as a result of constraints on imports from Argentina. However, the opening of two LNG import terminals in 2009 has helped to reverse the decline in Chile's natural gas use, and total consumption is expected to surpass the country's historical peak use within a few years.

OECD Europe

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Natural gas consumption in OECD Europe grows by 0.7 percent per year on average, from 19.5 trillion cubic feet in 2008 to 23.2 trillion cubic feet in 2035 (Figure 44), primarily as a result of increasing consumption in the electric power sector. Many governments in OECD Europe have made commitments to reduce greenhouse gas emissions and promote development of "clean energy." Natural gas potentially has two roles to play in reducing carbon emissions, as a replacement for more carbon-intensive coal-fired generation and as backup for intermittent generation from renewable energy sources. In the IEO2011 Reference case, natural gas is second only to renewables as Europe's most rapidly growing source of energy for electricity generation, as its share of total power generation grows from 20 percent in 2008 to 22 percent in 2035. Although not considered in the IEO2011 projections, recent actions by some European governments to reduce their reliance on nuclear power in the wake of Japan's Fukushima Daiichi nuclear disaster are likely to provide a further boost to natural gas use in electricity generation.

The growth of Europe's natural gas markets has been hampered somewhat by a lack of progress in reforms that would make natural gas markets more responsive to, or supportive of, electric power markets. The European Union has been attempting to implement legislation that would ease third-party access to Europe's natural gas transmission pipelines and thus allow independent operators access to existing infrastructure [68]. The European Commission ratified its Third Energy Package in 2009, and its stipulations were required to be passed into local law by March 3, 2011. The regulatory changes should increase spot trading and make natural gas markets more flexible by making it easier for market participants to purchase and transmit gas supplies (see section on "Natural gas prices in Europe").

OECD Asia

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Natural gas consumption in OECD Asia grows on average by 1.0 percent per year from 2008 to 2035. Over the projection period, natural gas consumption in Japan increases by only 0.3 trillion cubic feet, while consumption in South Korea increases by 0.6 trillion cubic feet and consumption in Australia/New Zealand increases by 0.9 trillion cubic feet (Figure 45). Total regional natural gas consumption increases from 6.2 trillion cubic feet in 2008 to 8.0 trillion cubic feet in 2035.

Japan's natural gas consumption grows modestly, by an average of 0.3 percent per year, from 3.7 trillion cubic feet in 2008 to 4.0 trillion cubic feet by 2035. In the short term, the country is likely to increase its use of natural gas to offset the loss of nuclear generating capacity that occurred when the Fukushima Daiichi power reactors were severely damaged by the March 2011 earthquake and tsunami. In the long term, declining population and an aging work force limit the country's natural gas demand, although a long-term shift away from previously planned reliance on nuclear power in the wake of the Fukushima disaster could boost natural gas use beyond the level projected in the IEO2011 Reference case. South Korea's natural gas consumption rises by 1.5 percent per year from 2008 to 2035, led by strong growth in the electric power sector. The share of the country's natural gas consumption used for electricity generation increases from 43 percent in 2008 to 54 percent in 2035.

In Australia/New Zealand, the industrial sector currently is the largest consumer of natural gas, accounting for about 60 percent of the region's total consumption in 2008. However, its share declines to less than 50 percent in 2035, despite average annual growth of 1.3 percent. A significant share of the mid-term growth in industrial natural gas consumption is attributable to fuel use at LNG plants. LNG exports more than double from 2008 to 2020, and LNG fuel use also more than doubles, while over the same period total industrial consumption increases by only 10 percent. In addition, natural gas use in the electric power sector grows strongly, from 0.3 trillion cubic feet in 2008 to 0.9 trillion cubic feet in 2035, as Australia—in its efforts to reduce carbon dioxide emissions—gradually increases the share of natural gas in its power generation mix in order to reduce its more carbon-intensive coal-fired generation.

Non-OECD natural gas consumption

Non-OECD Europe and Eurasia

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The countries of non-OECD Europe and Eurasia relied on natural gas for 50 percent of their primary energy needs in 2008—a larger share than for any other country grouping in IEO2011. Russia is the world's second-largest consumer of natural gas after the United States, with consumption totaling 16.8 trillion cubic feet in 2008 and representing 56 percent of Russia's total energy consumption. In the Reference case, Russia's natural gas consumption grows at a modest average rate of 0.1 percent per year from 2008 to 2035, reflecting a declining population and a shift away from natural gas to nuclear power in the electricity sector in an effort to diversify the power sector fuel mix and monetize natural gas through exports to OECD Europe and Asian markets. Expected efficiency improvements and other demand-side management measures limit growth in natural gas consumption over the long term.

Outside of Russia, natural gas consumption in non-OECD Europe and Eurasia increases by 0.4 percent annually over the projection period, from 8.2 trillion cubic feet in 2008 to 9.1 trillion cubic feet in 2035 (Figure 46). Natural gas is the largest component of the region's primary energy consumption, representing more than 40 percent of the total throughout the Reference case projection. The industrial sector remains the largest consumer of natural gas in non-OECD Europe and Eurasia, accounting for approximately 40 percent of total natural gas consumption in non-OECD Europe and Eurasia.

Non-OECD Asia

Among all regions of the world, the fastest growth in natural gas consumption is projected for non-OECD Asia, which accounts for 35 percent of the total increment in natural gas use in the Reference case and nearly doubles its share of total world natural gas consumption from 10 percent in 2008 to 19 percent in 2035. Natural gas use in non-OECD Asia increases by an average of 3.9 percent annually, from 11.3 trillion cubic feet in 2008 to 31.9 trillion cubic feet in 2035 (Figure 47).

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India and China lead the growth in natural gas consumption in non-OECD Asia. In both India and China, natural gas currently is a minor part of the overall energy mix, accounting for only 8 percent and 3 percent, respectively, of total energy consumption in 2008. Those shares are poised to increase over the projection, however, and natural gas accounts for 11 percent of total energy use in India and 6 percent in China in 2035 in the Reference case, as total natural gas consumption in the two countries combined increases by 12 trillion cubic feet from 2008 to 2035. For the other countries of non-OECD Asia, natural gas consumption increases by a total of 8 trillion cubic feet from 2008 to 2035.

China's central government is promoting natural gas as a preferred energy source. It 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 [77]. In the IEO2011 Reference case, China's natural gas consumption grows at an average rate of 5.5 percent annually over the projection period—the highest growth rate worldwide—to 6.8 trillion cubic feet in 2020 and 11.5 trillion cubic feet in 2035. Nevertheless, China does not achieve its targeted natural gas share, and coal continues to account for the largest share of its energy consumption. Natural gas provides 5 percent of China's energy supply in 2020 in the Reference case and surpasses 8.8 trillion cubic feet of consumption after 2025.

In India, natural gas consumption more than doubles between 2008 and 2015, with much of the growth resulting from increasing domestic supply. Natural gas demand has outstripped supply in India, with many industrial concerns and power generators being underutilized or having to run on more expensive liquid fuels for lack of natural gas. With the start of production from the Krishna Godavari field in 2009, some of the latent demand has begun to be met. Preliminary data indicate that India's natural gas consumption in 2009 was 23 percent above its consumption in 2008. Over the entire projection period, India's natural gas use grows by 4.6 percent per year, with supply constraints continuing to hold down consumption.

In the other countries of non-OECD Asia, natural gas already is a large component of the energy mix, representing 23 percent of the region's combined total energy consumption in 2008. In the Reference case, natural gas consumption in the region more than doubles, from 7.2 trillion cubic feet in 2008 to 15.4 trillion cubic feet in 2035.

Middle East

Total natural gas consumption in the Middle East doubles from 2008 to 2035, growing by an average of 2.7 percent per year. The region's industrial sector remains the most important natural gas consumer and accounts for 55 percent of total gas use in 2035. A significant portion of the increase in industrial consumption from 2008 to 2015 is attributed to the use of natural gas in LNG liquefaction plants and in gas-to-liquids (GTL) plants. Qatar more than doubles its LNG liquefaction capacity over the 7-year period and consequently more than doubles its fuel use in LNG liquefaction plants. The country's two GTL facilities also ramp up production over the same period. The Oryx GTL plant, which started production in 2007, is expected to consume around 120 billion cubic feet of natural gas per year and produce 30 thousand barrels of liquids per day. The Pearl GTL facility, when it reaches full production in 2012, will be the world's largest GTL plant. At full capacity it will consume 660 bllion cubic feet of natural gas per year and produce 140 thousand barrels of liquids per day, including diesel, naphtha, and kerosene. Industrial consumption of natural gas in the Middle East grows by an average of 4.5 percent per year from 2008 to 2015, with consumption in LNG and GTL facilities accounting for around one-half of the increase. After 2015, industrial gas consumption growth slows to a still robust rate of 2.9 percent per year.

Africa

In Africa, the electric power and industrial sectors account for most of the increase in demand for natural gas, as Africa's total natural gas consumption grows from 3.6 trillion cubic feet in 2008 to 9.1 trillion cubic feet in 2035. In West Africa, Nigeria is taking measures to end natural gas flaring and to prioritize natural gas use for domestic consumption over exports in order to support growing use in the electric power sector. Similarly, in Egypt, the government announced a moratorium on new export contracts until 2010. In order to continue development of its natural gas reserves, however, Egypt will need to maintain investment from the international oil and gas companies currently developing those reserves, but low domestic natural gas prices make it unlikely that Egypt will attract the necessary level of investment.

Non-OECD Central and South America

In the non-OECD nations of Central and South America, natural gas consumption increases on average by 2.5 percent per year, from 4.6 trillion cubic feet in 2008 to 8.8 trillion cubic feet in 2035. The electric power sector accounts for 42 percent of the region's total increase in demand for natural gas. Several countries in the region are particularly intent on increasing the penetration of natural gas for power generation, in order to diversify electricity fuel mixes that currently are heavily reliant on hydropower (and thus vulnerable to drought) and to reduce the use of more expensive oil-fired generation, which is often used to supplement electricity supply.

World natural gas production

In order to meet the consumption growth projected in the IEO2011 Reference case, the world's natural gas producers will need to increase supplies by almost 60 trillion cubic feet—or more than 50 percent—from 2008 to 2035. Much of the increase in supply is expected to come from non-OECD countries, which in the Reference case account for 81 percent of the total increase in world natural gas production from 2008 to 2035. Non-OECD natural gas production grows by an average of 2.0 percent per year in the Reference case, from 69 trillion cubic feet in 2008 to 117 trillion cubic feet in 2035 (Table 6), while OECD production grows by only 0.9 percent per year, from 41 trillion cubic feet to 52 trillion cubic feet.

Production of unconventional gas, which for the purposes of IEO2011 includes tight gas, shale gas, and coalbed methane, grows rapidly over the projection period, with OECD unconventional production growing on average by 3.2 percent per year, from 13 trillion cubic in 2008 to 31 trillion cubic feet in 2035. Over the same period, non-OECD unconventional production grows from less than 1 trillion cubic feet to 12 trillion cubic feet. However, numerous uncertainties could affect future production of unconventional natural gas resources. There is still considerable variation among estimates of recoverable shale resources in the United States and Canada, and estimates of recoverable unconventional gas for the rest of the world are more uncertain given the relatively sparse data that currently exist (see section on "International shale gas resources"). Additionally, the hydraulic fracturing process used to produce shale gas resources requires a significant amount of water, and many of the areas that have been identified globally as having shale gas resources have limited supplies of water. Furthermore, there is additional uncertainty surrounding access to the resources due to environmental concerns (see section on "shale gas: Hydraulic fracturing and environmental issues"). For instance, development in parts of the Marcellus shale in the United States has been inhibited somewhat by limitations on the issuance of drilling permits, especially in the State of New York. France has recently taken legislative actions to ban hydraulic fracturing in that country, and South Africa has placed a moratorium on hydraulic fracturing while it investigates how best to regulate it to ensure that the environment is protected.

OECD Production

OECD Americas

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Natural gas production in the OECD Americas grows by 34 percent from 2008 to 2035. The United States, which is the largest producer in the OECD Americas and in the OECD as a whole, accounts for more than 60 percent of the total regional production growth, with an increase from 20.2 trillion cubic feet in 2008 to 26.4 trillion cubic feet in 2035 (Figure 48). Increases in U.S. shale gas production more than offset declines in other categories, growing more than fivefold from 2.2 trillion cubic feet in 2008 to 12.2 trillion cubic feet in 2035. In 2035, shale gas accounts for 47 percent of total U.S. natural gas production, tight gas accounts for 22 percent, lower 48 offshore production accounts for 12 percent, and coalbed methane accounts for 7 percent. The remaining 12 percent comes from Alaska and other associated and nonassociated lower 48 onshore resources. As a result of lower natural gas prices, an Alaska pipeline is not economical before 2035, and so it does not get built in the forecast.

One of the keys to the U.S. production growth is advanced production technologies, especially the combined application of horizontal drilling and hydraulic fracturing techniques that has 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. Although shale gas resources are distributed widely across the United States, current estimates indicate that more than one-half of the shale gas resource base of 862 trillion cubic feet is concentrated in the Northeast. The Gulf Coast States also have considerable shale gas resources, and in the IEO2011 Reference case production increases occur predominantly in the Northeast and along the Gulf Coast, with smaller increases expected in other areas. U.S. shale gas production has continued to grow despite low natural gas prices. However, 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 1.5 percent per year on average over the projection period, from 6.0 trillion cubic feet in 2008 to 9.0 trillion cubic feet in 2035. As in the United States, much of the production growth comes from growing volumes of shale gas. Although Canada produced only about 4 billion cubic feet of shale gas in 2008, it has the potential to reach 169 billion cubic feet by 2012, according to estimates from Canada's National Energy Board [78]. In addition, three proposed LNG liquefaction and export facilities would use feedstock gas from the Horn River and Montney shales and tight gas plays. If all three facilities were built and operated at their maximum proposed capacity, Canada would need to produce approximately 1.3 trillion cubic feet per year to support them—incidentally, about the same volume as the decrease in net pipeline exports of natural gas from Canada to the United States projected in the IEO2011 Reference case.

In addition to the small but growing volumes of shale gas that Canada produces, it also currently produces small volumes of gas from coalbeds and significant volumes from tight reservoirs. In 2008, about 30 percent of Canada's natural gas production came from tight reservoirs, which Canada considers to be conventional production [79]. 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 0.28 trillion cubic feet of coalbed methane production in 2008. In 2001, coalbed methane activity in the province consisted of no more than a few test wells [80].

Mexico's natural gas production remains fairly flat, growing only from 1.7 trillion cubic feet in 2008 to 2.1 trillion cubic feet in 2035. The country faces substantial difficulties in attracting the investment and technology improvements needed to increase production, especially if it wants to try to produce hydrocarbons from its shale plays, the most prospective of which are extensions of the successful Eagle Ford shales in the United States. In March 2011, Mexican state-owned petroleum company, Petróleos Mexicanos (PEMEX), announced that it had results from its first shale gas evaluation well in the Eagle Ford shales and that it was considering drilling 10 additional evaluation wells targeting shales that had as much potential of yielding crude oil as of yielding natural gas or other liquids [81].

OECD Europe

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Outside of Norway, natural gas production in OECD Europe is generally in decline, with production falling from 8.6 trillion cubic feet in 2000 to 7.1 trillion cubic feet in 2008. Over the same period, Norway's production grew from 1.9 trillion cubic feet to 3.5 trillion cubic feet, slowing the rate of decline in OECD Europe as a whole, but not reversing it. Over the projection period, production of natural gas in OECD Europe continues to decline at an average annual rate of 0.9 percent (Figure 49).

While production of natural gas from conventional reservoirs declines, growing production of tight gas, shale gas, and coalbed methane slows the rate of overall decline. Exploratory drilling and/or leasing for shale gas is ongoing in several countries in OECD Europe. Poland is at the forefront of shale gas exploration activity in Europe, offering attractive fiscal terms and enjoying the participation of multiple companies actively drilling in multiple basins. Halliburton, working for the Polish state gas firm Polskie Gornictwo Naftowe i Gazownictwo (PGNiG), fractured the country's first shale well in late 2010 [82]. In addition, leasing and drilling activity for coalbed methane is ongoing in at least five European countries (Turkey, Italy, France, Poland and the United Kingdom), with the United Kingdom and Poland both having recently begun producing small amounts of coalbed methane gas [83].

OECD Asia

Natural gas production in the Australia/New Zealand region grows from 1.7 trillion cubic feet in 2008 to 5.7 trillion cubic feet in 2035 in the Reference case, at an average rate of 4.5 percent per year—the strongest growth in natural gas production among OECD regions. In 2008, the Northwest Shelf area of Australia's Carnarvon Basin accounted for around 59 percent of total production in the Australia/New Zealand region [84], with much of the production used as feedstock at the Northwest Shelf LNG liquefaction facility. Other areas and basins in Australia provided another 32 percent of the region's total production in 2008. New Zealand's natural gas production accounted for around 9 percent of the 2008 regional total.

Coalbed methane, from the Bowen-Surat Basin in eastern Australia, accounted for between 8 percent and 9 percent of total production in Australia in 2008 [85], and its share is certain to grow in the future, as it provides natural gas supplies to satisfy the area's demand growth and to feed proposed LNG export projects. In late 2008, New Zealand also began producing natural gas from coalbeds, with small volumes from pilot production being piped to a nearby power plant and used to generate electricity [86].

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 are prospective for tight gas and shale gas. The Australian company Latent Petroleum drilled its first appraisal well in the Warro tight gas field in the Perth basin in 2009, and it plans to start producing natural gas from the field in 2013 [93]. The Western Australia state government has been actively promoting the development of unconventional natural gas resources. In 2009 the state government cut in half the royalty rate for tight gas, from 10 percent to 5 percent [94], and in 2010 it announced that it would appoint a drilling expert in an effort to help alleviate the deficit that exists in the state for rigs that can drill to the necessary depths for tight and shale gas, and for equipment for hydraulically fracturing tight gas and shale gas wells [95]. Shale gas development is most active in the Cooper basin, which lies mainly in the state of South Australia. The country's first test well aimed specifically at a shale formation was drilled in the Cooper Basin by Beach Petroleum in late 2010. The company plans to hydraulically fracture the well in 2011 [96].

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 2008, natural gas production in Japan and South Korea accounted for only 5 percent and 1 percent of their natural gas consumption, respectively. Although 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, the IEO2011 Reference case does not include methane hydrate resources in its estimates of natural gas resources, and the development of hydrates on a commercial scale is not anticipated during the projection period.

Non-OECD Production

Middle East

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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 2008. With more than 40 percent of the world's proved natural gas reserves, the Middle East accounts for the largest increase in regional natural gas production from 2008 to 2035 (Figure 50) and for 26 percent of the total increment in world natural gas production in the Reference case.

The strongest growth among Middle East producers from 2008 to 2035 in the IEO2011 Reference case comes from Qatar, where natural gas production increases by 5.4 trillion cubic feet, followed by Iran (5.3 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 9.8 percent per year over the projection, it is a relatively minor contributor to regional gas supplies. In 2035, Iraq's natural gas production totals only 0.8 trillion cubic feet, or about 3 percent of the Middle East total.

Iran has the world's second-largest reserves of natural gas, after Russia, and currently is 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 2008, Iran reinjected more than 1 trillion cubic feet of natural gas, or 16 percent of its gross production. In 2009, Iran began enhanced oil recovery operations at the Agha-Jari oil field, where it plans to raise oil production by 60,000 barrels per day by injecting 1.3 trillion cubic feet of natural gas annually, more than doubling the 2008 reinjected volumes [100]. In 2020, Iran is estimated to need between 3.7 trillion and 7.3 trillion cubic feet of natural gas per year for reinjection [101]. The higher estimate is greater than the projected total for Iran's marketed natural gas production in 2020. 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 2.3 percent per year, from 2.8 trillion cubic feet in 2008 to 5.2 trillion cubic feet in 2035. The Saudi 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 also sour natural gas fields, making them relatively expensive to produce, at an estimated cost of $3.50 to $5.50 per million Btu [102]. The IEO2011 Reference case assumes that Saudi Arabia's policy of reserving natural gas production for domestic use persists throughout the projection period, and that no natural gas is 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

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Almost 17 percent of the global increase in natural gas production is expected to come from non-OECD Europe and Eurasia, which includes Russia, Central Asia, and non-OECD Europe. In the Reference case, natural gas production in the region as a whole increases from 30.4 trillion cubic feet in 2008 to 40.4 trillion cubic feet in 2035 (Figure 51). Russia remains the dominant natural gas producer, accounting for more than 75 percent of the region's production throughout the projection.

In 2008, Russia produced 23.4 trillion cubic feet of natural gas. Preliminary estimates indicate that its production fell by 12 percent in 2009 to 20.6 trillion cubic feet. The production decline was due not to a lack of resources or production capacity but rather to the global economic downturn and resulting decline in natural gas demand in Russia and its gas export markets. Russian natural gas, whether consumed domestically or exported, generally is not priced according to gas market fundamentals. Normally, a decrease in demand for natural gas when supply is relatively abundant tends to drive prices down, encouraging a recovery in demand. Instead, Russian natural gas prices remained largely unchanged after the economic downturn. Prices for natural gas exports from Russia usually are linked to world oil prices by contract. Because domestic prices are largely regulated, however, the artificially low prices in place before the economic crisis did not change, and as Russia's domestic demand for natural gas declined, production for the domestic market also dropped, by 8 percent (1.3 trillion cubic feet) from 2008 to 2009. In addition, Russia's apparent net exports of natural gas declined by 23 percent to 5.1 trillion cubic feet in 2009. In the IEO2011 Reference case, Russia's natural gas production grows on average by 1.1 percent per year over the projection period, as exports to Europe recover and both LNG and pipeline exports to Asia increase.

If Russia is to increase exports to Asia while at least maintaining exports to Europe, it must invest in new fields. Moreover, it will require such investment simply to maintain current production levels, because production is in decline at its three largest gas fields (Yamburg, Urengoy, and Medvezh'ye) [103]. 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 Russian state firm Gazprom [104]. There had been little progress on exporting 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 at the field is scheduled to start in 2012 and over the course of several years ramp up to more than 4 trillion cubic feet per year [105]. To the northeast of Bovanenkovo lies the Tambeiskoye field, which is majority-owned by Russia's largest independent gas producer, Novatek. 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 [106]. Finally, Gazprom is scheduled to make a final investment decision on its Shtokman field in the Barents Sea by the end of 2011. The field is estimated to hold more than 130 trillion cubic feet of natural gas reserves, and the first development phase would see production of 0.8 trillion cubic feet per year [107].

Natural gas production in Central Asia (which includes the former Soviet Republics) grows by 1.1 percent per year on average, from 5.9 trillion cubic feet in 2008 to 7.9 trillion cubic feet in 2035. Much of the growth is expected to come from Turkmenistan, which already is a major producer and accounted for more than 40 percent of the region's total production in 2008. Turkmenistan is just beginning to develop its recently reassessed giant Yolotan 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 by the end of 2011 [108]. Initial natural gas production from the Yolotan field probably will be exported by pipeline to China. Further expansion of production in Turkmenistan and Central Asia will depend on securing markets and transit routes to reach markets in China. Also contributing to Central Asia's projected 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 0.7 trillion cubic feet to the country's annual production.

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Africa

Substantial growth is projected for natural gas production in Africa, from a total of 7.5 trillion cubic feet in 2008 to 11.1 trillion cubic feet in 2020 and 14.1 trillion cubic feet in 2035 (Figure 52). In 2008, almost 78 percent of Africa's natural gas was produced in North Africa, mainly in Algeria, Egypt, and Libya. West Africa accounted for another 20 percent of the 2008 total, and the rest of Africa accounted for almost 3 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, faster production growth is projected for West Africa, with annual increases averaging 3.1 percent, as compared with an average of 2.2 percent for 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 2012 [109]. Still, because security concerns and uncertainty over terms of access in Nigeria limit production growth in West Africa, North Africa remains the continent's leading region for natural gas production over the course of the projection.

North Africa also leads the region in shale gas activity. Cygam Energy conducted hydraulic fracturing at a well in the Tunisian portion of the Ghadames basin in 2010, and Cygam and other companies have plans for several more exploration and appraisal wells to be drilled in Tunisia and Morocco over the next year [110]. There is also interest in shale gas development in South Africa, where several companies are involved in evaluating permit areas for shale gas potential. However, no new wells aimed at shale gas have been drilled so far, and several of the current permits do not actually allow new drilling activity [111]. Companies are also exploring coalbed methane opportunities in South Africa, as well as in neighboring Zimbabwe and Botswana [112]. In the shorter term, conventional offshore discoveries in the Rovuma basin off the coast of Mozambique and increased estimates of natural gas resources in the Kudu field off the coast of Namibia could add to southern Africa's natural gas production.

Non-OECD Asia

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Natural gas production in non-OECD Asia increases by 11.8 trillion cubic feet from 2008 to 2035 in the IEO2011 Reference case, with China accounting for 39 percent of the growth and India 23 percent (Figure 53). From 2008 to 2035, China has the largest projected increase in natural gas production in non-OECD Asia, from 2.7 trillion cubic feet in 2008 to 7.3 trillion cubic feet in 2035, for an average annual increase of 3.8 percent. Much of the increase in the later years comes from unconventional reservoirs (Figure 54). China already is producing small volumes of coalbed methane and significant volumes of tight gas. The actual volumes of tight gas are unknown, as China considers tight gas to be conventional and does not report it separately. However, China produced and utilized 88 billion cubic feet of coalbed methane in 2009 and 127 billion cubic feet in 2010. China is trying to encourage the development of coalbed methane resources, and one way it is doing so is by offering producers a subsidy of roughly $1 per million Btu [113]. In addition, there has been great interest in China's potential for shale gas production, and several international companies have partnered with Chinese companies to explore potential shale resources. So far, most of the activity is at the evaluation stage, but a few wells targeting shale resources have been drilled or are planned [114].

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Natural gas production in India grows at an average annual rate of 4.6 percent over the projection period. Most of the growth in India's natural gas production is expected in the near term, averaging 11.8 percent per year as total production grows from 1.1 trillion cubic feet in 2008 to 2.5 trillion cubic feet in 2015. Much of the expected increase comes from a single development, the Dhirubhai-6 block in the Krishna Godavari Basin, where production began in April 2009. Production had been anticipated to reach 2.8 billion cubic feet per day (1.02 trillion cubic feet per year), but actual production peaked at 2.1 billion cubic feet per day (0.77 trillion cubic feet per year) in the third quarter of 2010 before falling back to 1.5 billion cubic feet per day (0.55 trillion cubic feet per year) in the fourth quarter [115]. Even if production is maintained at the lower level of 0.55 trillion cubic feet per year, it will represent a 50-percent increase over 2008 production in a period of just 2 years.

In the longer term, unconventional resources are expected to account for a significant portion of the growth in India's natural gas production. India is already producing small volumes of natural gas from coalbed methane deposits. In 2008, total coalbed methane production amounted to less than 1 billion cubic feet [116]. Leasing and drilling activity has been progressing for several years, and more meaningful volumes could be produced as early as the 2013 to 2014 time frame [117]. In addition, India has several basins that are prospective for shale gas. In late 2010 the Indian state Oil and Natural Gas Company (ONGC) drilled the country's first well specifically targeting shale gas resources [118]. The Indian government plans its first licensing round for shale gas acreage in the second half of 2011, after it has established new financial and contractual regimes for shale gas activity [119].

Outside China and India, non-OECD Asian natural gas production grows at an average annual rate of only 1.5 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. In the mid-term, Indonesia's natural gas production increases somewhat as a result of the new Tangguh LNG export project, which came on line in the second half of 2009 and ramped up to full production in 2010 [120]. Indonesia could also become the first country to produce LNG from an unconventional gas source, ahead of Australia's coalbed methane to LNG projects, which are scheduled to come on line around 2015. Indonesia has at least 20 active production-sharing contracts for ongoing coalbed methane drilling [121]. Indonesia expects first coalbed methane production in 2011, with small production flows feeding a local power plant. In 2012, natural gas from coalbeds could flow to the Bontang LNG liquefaction plant [122].

Non-OECD Central and South America

Natural gas production in the non-OECD economies of Central and South America grows by more than 85 percent from 2008 to 2035 (Figure 55). The fastest growth, averaging 6.9 percent per year, is projected for Brazil, where recent discoveries of oil and natural gas in the subsalt Santos basin are expected to increase the country's natural gas production. Much of that natural gas lies far from shore, and because of a lack of current infrastructure to bridge the distances, initial natural gas production associated with oil extraction from the subsalt fields is likely to be reinjected for enhanced oil recovery rather than being brought to market. Over the longer term there are plans to connect the subsalt gas and oil fields to shore with natural gas pipelines, or to produce and liquefy Brazil's natural gas at sea, on floating platforms from which LNG could be loaded onto ships for transport to existing regasification terminals on the country's coast.

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Despite recent declines in production, Argentina is still the leading producer of natural gas in Central and South America, accounting for more than 40 percent of the region's total production in 2008. Argentina is also leading the region in its pursuit of tight gas and shale gas. Much of the decline in production from conventional reservoirs can be attributed to wellhead price controls instituted in 2004, which froze wellhead prices at around $1.40 per million Btu [123]. Much of the interest in tight and shale gas can be attributed to Argentina's Gas Plus program, which allows natural gas to be sold at prices of up to $5.00 per million Btu [124]. Argentina already is producing natural gas from tight reservoirs, and Apache Corporation in December 2010 drilled the first horizontal well with multiple fracture stages in a shale play in Argentina [125].

World natural gas trade

The geographical mismatch of locations with natural gas resources and locations with rising demand indicates continued expansion of international trade through 2035. In the IEO2011 Reference case, trade in natural gas between OECD and non-OECD countries grows throughout the projection at an average rate of around 1 percent per year, so that in 2035 the total volume crossing between the two country groups is 17.4 trillion cubic feet. Much of the driving force behind the increase is demand for deliveries into countries of OECD Europe. In 2035, approximately 15.6 trillion cubic feet per year of natural gas imports flow to OECD Europe alone—almost double the volume of current imports to the region. At the same time, the required volumes of net imports for OECD regions in Asia and the Americas decline.

The increase in world trade results in part from efforts in many countries to commercialize natural gas resources through construction of LNG production facilities. International trade in natural gas currently is undergoing rapid transformation, as a massive expansion of LNG production capacity in several countries continues. In the past 5 years there has been a 40-percent increase in world LNG production capacity, from approximately 176 million metric tons per year at the end of 2005 to 260 million metric tons per year at the end of 2010, with an impact on world markets that is likely to provide increased flows among regions for many years. As world economies recovered in 2010, LNG flows increased by nearly 20 percent and set a new record high for trade levels. Consumption of LNG—much of which crosses regional boundaries—totaled approximately 10.4 trillion cubic feet in 2010 [126].

Although LNG trade has grown considerably faster in recent years, flows of natural gas by pipeline still are an integral part of world natural gas trade in the IEO2011 Reference case, which includes several new long-distance pipelines and expansions of existing infrastructure through 2035. Current international trade of natural gas by pipeline occurs in the largest volumes 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 IEO2011 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 likely 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. By the end of 2011, 19 countries are expected to be exporting LNG, as compared with 12 in the years before 2000. Suppliers of LNG, including new exporting countries such as Yemen and Russia, have successfully expanded marketing efforts, so that the list of LNG importing countries has grown to 26 in 2011 from 12 before 2000. In the past two years alone, Brazil, Argentina, Chile, Canada, and Kuwait have begun importing LNG for the first time.

Although the rapid expansion of LNG trade in recent years has occurred primarily through the commercialization of large reserves of conventional resources, interest in developing unconventional resources such as natural gas shale formations also has grown significantly. The results already are noticeable in North America, with the current development of shale resources and coincident reduction in demand for imports. Although North America once was considered to be a likely destination for LNG supplies, increases in U.S. natural gas production and decreasing prices in U.S. markets have resulted in the movement of LNG supplies to higher-priced markets in South America, Europe, and Asia instead.

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 unconventional resources is not necessarily a countervailing force to growing international trade. For example, the development of shale gas resources in Canada and coalbed methane in Australia already has resulted in proposals for the construction of liquefaction facilities from which LNG would be transported to Asian markets.

OECD natural gas trade

In 2008, about one-quarter of natural gas demand in OECD nations was met by net imports from non-OECD countries. OECD reliance on supplies from non-OECD countries is expected to remain fairly constant over the projection, even as significant differences in the trade profiles of the OECD regions of the Americas, Europe, and Asia evolve. With continued exploitation of unconventional resources in the United States and Canada, the OECD Americas region remains relatively self-sufficient throughout the projection. Both OECD Europe and OECD Asia have large requirements for natural gas imports through 2035, but OECD Asia's decline while OECD Europe's expand significantly.

OECD Americas

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Regional net imports among the nations of the OECD Americas begin a downward trend early in this decade that extends through 2035 in the IEO2011 Reference case (Figure 56). 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, which totals 12 trillion cubic feet per year in 2035, double the level projected in last year's outlook.

Increased domestic production lessens the need for U.S. net imports from approximately 13 percent of total supply in 2008 to less than 1 percent in 2035. The reduction is reflected through most of the years of the projection in lower pipeline flows from Canada, which has delivered more than 2.5 trillion cubic per year to the United States since 1995. In addition, several new LNG import facilities that have come on line in the United States over the past 5 years are largely underutilized in the projection. In fact, the facilities currently are serving as temporary storage sites for LNG that has been brought to the United States for re-export to other countries. Although applications have been filed for the liquefaction and export of domestically produced natural gas from the Gulf Coast, considerable uncertainty surrounds the issue. Two applications to export to Free Trade countries have been approved, and applications to export to non-Free Trade countries are under consideration but have not been approved as of early 2011.²² Currently, the only liquefaction and exportation of domestically produced LNG from the United States is from a Conoco facility in Kenai, Alaska. The facility has been in operation since 1969, exporting less than 65 billion cubic feet per year to Japan, with authorization to export through 2013. Recently, Conoco has announced plans to mothball the facility and has indicated that the nuclear crisis in Japan has not altered the decision [127].

In the IEO2011 Reference case, the near-term decline in pipeline exports from Canada to the United States is reversed by increases in Canada's production of tight gas, shale gas, and coalbed methane. The unconventional resources are concentrated in the western portions of the country, where substantial infrastructure additions will be needed to bring the supplies to market. Nonetheless, substantial reserves in the Montney Shale in east central British Columbia have shown significant potential and attracted developmental interest and investment by several large producers. Canada has an operating LNG import terminal at St. Johns, New Brunswick, and several others that are either approved or in the planning stages. However, construction of the facilities has been postponed. Interest on behalf of project developers has lessened as U.S. production has grown over the past 2 years [128]. In fact, LNG could play a significant role in Canada's exports by the end of the projection period, with three export terminals proposed for the Kitimat area in British Columbia, all to serve Asian markets.

In the OECD Americas as a whole, the growing dependence of Mexico and Chile on imports offsets the reduction in U.S. import demand. As Mexico's domestic production fails to keep pace with consumption growth, its net imports grow from 0.4 trillion cubic feet in 2008 to 2.9 trillion cubic feet in 2035. Flows from the United States, which currently account for about 15.7 percent of Mexico's natural gas supply, increase substantially in the projection. LNG supply, a steady volume of which has been delivered to the country since 2005, also is increasingly important to meeting growing demand in the country. The newer Costa Azul LNG Terminal in Baja California on the country's western coast has been used infrequently. Supplies from Indonesia, once envisioned for the terminal, have been redirected to Asian markets. However, the Altamira LNG Terminal on Mexico's eastern coast has received LNG shipments on a regular basis, with volumes totaling more than 100 billion cubic feet per year since 2008. LNG supplies also are expected to increase following the completion in 2011 or 2012 of another terminal on the west coast, in Manzanillo. The Manzanillo terminal is expected to receive supplies regularly from Peru's LNG export terminal, which was completed in 2010 [129].

Chile produced a relatively modest amount of natural gas in 2008—66 billion cubic feet, as compared with Mexico's 1,694 billion cubic feet. Until recent years, Chile relied on Argentina to supply most of its natural gas demand. In 2004, imports from Argentina supplied 282 billion cubic feet of the 293 billion cubic feet of natural gas consumed in Chile [130]. Wellhead gas prices, held artificially low by Argentina's price controls, had the dual effect of encouraging demand for natural gas and discouraging investment in exploration and production. As a result, Argentina had to limit natural gas supplies available for export in order to meet domestic demand. Consequently, Chile moved to ensure that it would be able to receive gas from other sources, by building two LNG regasification terminals, one in Quintero near Santiago and one in the northern town of Mejillones [131]. To increase natural gas supplies, GDF Suez announced that it would construct an onshore LNG storage facility in Northern Chile by 2013 [132]. The diversification of natural gas suppliers already has helped Chile improve its energy security, and natural gas imports are likely to continue to rise in the future.

OECD Europe

Continued growth is expected for natural gas imports into OECD Europe, as global LNG supplies continue to expand rapidly over the next few years, and as the Medgaz pipeline from Algeria begins exporting gas to Spain in 2011. Over the term of the projection, OECD Europe's total natural gas imports increase by an average of 2.1 percent per year, as local production sources in the Netherlands and United Kingdom decline while demand increases. Pipeline sources are projected to be significant contributors to the incremental 6.6 trillion cubic feet of imports needed in the region. The Nord Stream pipeline from Russia and the Galsi pipeline from Algeria could push additional natural gas supplies into OECD Europe as soon as 2011 and 2014, respectively, according to planned start dates.
For the second year in a row, LNG supplies to OECD Europe increased significantly in 2010, even as overall consumption generally declined [133]. Major shifts in international trade partners and pricing are occurring in the region. European buyers continue to favor LNG as a result of lower spot prices relative to prices for oil-indexed pipeline supply contracts. For example, imports of LNG were up by 26 percent in 2010, and imports of pipeline gas from Russia were down by almost 2 percent. The contrast was even more striking in 2009, when LNG imports to the region increased by more than 20 percent, and imports from Russia were down by 11.9 percent [134].

The recent increase in LNG supplies to 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. Since the onset of the financial crisis in late 2008, which resulted in lower natural gas demand and excess supplies worldwide, buyers have resorted to buying greater volumes of LNG on spot markets rather than opting for supplies through oil-linked contracts.

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 [135]. The subsequent loss of market share by suppliers with less flexibility in pricing over the past 2 years 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. The extent of such changes over the long term remains to be seen.

Contributing to the abundance of natural gas supplies available for import to OECD Europe in 2009 were additional LNG imports from Qatar, which at least in part are priced to coincide with spot market prices in the United Kingdom. Qatar in early 2011 completed a massive investment in its LNG production capacity, establishing itself as by far the largest producer of LNG in the world. As a result of the construction program, Qatar's LNG production capacity has risen to 3.8 trillion cubic feet per year, and new regasification facilities have been opened in the United States, the United Kingdom, and Italy.

OECD Asia

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Currently, the largest LNG importers in the world are in OECD Asia, which receives a substantial portion of its overall natural gas supply in the form of LNG imports. In the IEO2011 Reference case, Japan and South Korea continue to receive the vast majority of their natural gas supplies as LNG; however, demand growth is relatively low in both countries, and the growth in their natural gas imports is more than offset by growing exports from Australia. As a result, OECD Asia's net demand for imports declines over the projection period, from 4.3 trillion cubic feet in 2008 to 2.1 trillion cubic feet in 2035 (Figure 57).

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 (representing 4.4 percent of world consumption in 2008). Because the two countries are almost entirely dependent on LNG imports for natural gas supplies, overall consumption patterns are translated directly into import requirements. As a result, Japanese and South Korean companies actively pursue opportunities to be foundation customers for greenfield Pacific liquefaction projects. For example, Japanese and South Korean companies have signed firm contracts for significant shares of the output from a variety of LNG projects in the Asia Pacific region, including Russia's Sakhalin 2 project, completed in 2009, and Australia's Pluto project, which is scheduled for completion in 2011.

Australia is by far the most active LNG exporter among OECD countries and one of the most active countries in the world for future LNG development. In 2008, Australia exported 0.5 trillion cubic feet of natural gas from its two operating LNG export facilities. 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. Australia had two new liquefaction projects under construction in 2011, Pluto and Gorgon, both drawing gas from fields in the Carnarvon Basin in the northwest. First exports of LNG from the Pluto project, which is majority-owned by Woodside Petroleum, Ltd., are expected by the end of 2011, and shipments of LNG from Chevron's mammoth Gorgon project are expected in 2014 [136]. The two projects together will expand Australia's export capacity by close to 1.0 trillion cubic feet per year.

As a result of the two projects above and numerous others that have been proposed, Australia's exports of natural gas more than triple from 2008 to 2020 in the Reference case, to 1.6 trillion cubic feet, and continue growing through 2035. Two additional liquefaction projects based off Australia's northwest coast aim for final investment decisions in 2011. The Wheatstone project would be the fourth independent liquefaction project to draw gas from the Carnarvon Basin, and Ichthys LNG would be the first project to draw gas from the Browse Basin, which lies between the Carnarvon and Bonaparte Basins [137].

Additionally, there are also at least four separate liquefaction projects planned for eastern Australia. In October 2010, BG Group approved a final investment decision for the Queensland Curtis LNG Project, which is planned to export up to 0.4 trillion cubic feet of LNG per year by 2014 and is underpinned by contracts with buyers in Chile, China, Japan, and Singapore [138]. Three other projects also are planned, using coalbed methane supplies from the Bowen-Surat Basin. Final investment decisions are expected in 2011 and first gas production around 2015 [139]. Not all of the proposed projects and expansions are assumed to go forward in the IEO2011 Reference case, because some of them appear to be competing for the same reserves to supply their facilities.

Non-OECD natural gas trade

Net exports of natural gas from the non-OECD region as a whole grow from 13.0 trillion cubic feet in 2008 to 17.4 trillion cubic feet in 2035 in the IEO2011 Reference case. The fastest growth in international trade occurs in the near term, as a result of growing exports from new LNG projects in the Middle East and new natural gas pipelines from Africa to Europe. The vast natural gas resource base in non-OECD countries points to their continued ability to meet incremental growth in natural gas demand 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 considerably less of their overall production to OECD countries over time. In 2008, 18.8 percent of non-OECD natural gas production was exported. The share peaks before 2015 at nearly 20 percent, as the current construction of LNG infrastructure and resulting boost in LNG exports is not met by a similar surge in consumption. Consequently, the share of non-OECD natural gas production exported to OECD countries declines gradually through the remainder of the projection.

Non-OECD Europe and Eurasia

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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—exceeding the combined net exports of all other non-OECD regions in the IEO2011 Reference case. Net exports from non-OECD Europe and Eurasia rise from 5.3 trillion cubic feet in 2008 to 14.2 trillion cubic feet in 2035, at an average annual rate of 3.7 percent (Figure 58). 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 2.8 percent per year, from 6.6 trillion cubic feet in 2008 to 14.0 trillion cubic feet in 2035. LNG and pipeline exports from Russia to customers in both Europe and Asia increase throughout the projection.

Despite recent declines in demand for Russian natural gas in Europe, the country has numerous projects under construction or in planning that, along with its extensive resource base, could meet future needs of importers. In late 2011, construction of the first of two parallel lines for the new Nord Stream pipeline is scheduled to be completed, with a capacity of almost 0.8 trillion cubic feet of natural gas per year across the Baltic Sea to Germany. Flows through the Nord Stream pipeline, for which a second, parallel pipe is under construction and planned for completion by 2013, are expected 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.

Russia has several other proposed export pipeline projects, including the South Stream pipeline, which would carry natural gas across the Black Sea, bypassing Ukraine on its way to European markets. In addition, Russia is moving forward on developing its massive Shtokman field in the Barents Sea, with plans to make a final investment decision by the end of 2011 to build related LNG facilities and a pipeline into Europe by 2017 [140]. The IEO2011 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 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 [141]. By the end of 2011, the pipeline will have a capacity of 1.1 trillion cubic feet per year. Initial flows to date have been considerably less than capacity, however. Additional export volumes are expected to come from Turkmenistan's giant South Yolotan-Osman field and could also come from fields in Kazakhstan. In the IEO2011 Reference case, exports from Central Asia grow from 2.4 trillion cubic feet in 2008 to 3.7 trillion cubic feet in 2035, with increases averaging 1.7 percent per year.

Middle East

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Net exports of natural gas from the Middle East grow at an annual rate of 3.6 percent, as flows from the region increase from 1.8 trillion cubic feet in 2008 to 4.8 trillion cubic feet in 2035 (Figure 59). An important factor in the increase, particularly in regard to brisk growth in volumes in the near term, is the rise of LNG supplies from Qatar, which went 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 2035. 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 mega-sized liquefaction trains under construction since 2008. Each train has the capacity to produce the equivalent of 0.36 trillion cubic feet of natural gas per year for export [142].

Qatar's natural gas exports grow by an estimated average of 12.5 percent per year from 2008 to 2015 in the Reference case, then slow to an average increase of just 0.9 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 [143]. 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 numerous export projects under consideration through the development of its portion of those reserves. The IEO2011 Reference case projects significant flows from Iran, so that by 2035 the country is a net exporter of 1.4 trillion cubic feet per year. Nonetheless, the country as of 2008 was just barely a net importer, receiving slightly higher volumes of natural gas from Turkmenistan than it sent to Turkey (resulting in net imports of 0.1 trillion cubic feet). Although its first LNG export plant is under construction, Iran is without international partners and without any 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.

Elsewhere in the Middle East, a second LNG train was completed in Yemen in 2010, giving the country total LNG export capacity of 0.4 trillion cubic feet per year [144]. Additionally, Oman and the United Arab Emirates also export LNG from the Middle East. Nonetheless, the potential for growth in exports from those and other countries in the Middle East appears to be limited by the growth of domestic demand, which has even resulted in significant volumes of LNG imports for Kuwait and likely upcoming volumes for the United Arab Emirates (UAE), which completed construction of a facility for importing LNG in November 2010 and received its first cargo a month later [145]. Both Oman and UAE also are currently importing natural gas via pipeline from Qatar. The IEO2011 Reference case projects a similar trend for producers in the Arabian Peninsula region as a whole, including Kuwait, Oman, UAE, and Yemen. As a group, they received net imports of less than 0.1 trillion cubic feet of natural gas in 2008, but the volume of imports rises throughout the projection, and net imports into the Arabian Peninsula in 2035 total 3.0 trillion cubic feet.

Africa

Net exports of natural gas from Africa increase in the projection at a rate of 1.0 percent per year (Figure 60). In 2008, the region's net exports totaled about 3.9 trillion cubic feet, led by net exports of 3.0 trillion cubic from North Africa. Approximately one-half of the exports from North Africa are deliveries 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.

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The increased volumes of natural gas exports from Africa result in part from a large expansion of infrastructure underway in Algeria for export capacity by pipeline and from LNG terminals. The Medgaz pipeline, which has a planned capacity of 0.3 trillion feet per year, began transporting supplies from Algeria to Spain in March 2011 [146]. Two liquefaction projects also are progressing in Algeria: the Gassi Touil project and a new liquefaction train at the existing Skikda export facility. Together they are expected to increase Algeria's LNG export capacity by 0.4 trillion cubic feet per year by 2013. In addition, a consortium led by Algeria's national oil and natural gas company, Sonatrach, and Italian utility Edison S.p.A. is planning to construct the Gasdotto Algeria-Sardegna-Italia Pipeline (GALSI) from Algeria to Italy by 2014, increasing the capacity for natural gas trade between the two countries by a total of 0.4 trillion cubic feet per year. The project timeline for GALSI, however, has slipped several times and a final investment decision has not been made on the project.

Any additional major expansions of export capacity from North Africa are projected to be dependent on the Trans-Sahara natural gas pipeline. The pipeline, if built, would stretch 2,800 miles to bring natural gas from Nigeria, across Niger, and connecting in Algeria to export pipelines to Europe. The Trans-Sahara pipeline was given the official go-ahead in 2009, having been declared economically and technically feasible, and 2015 was set as the official targeted start date [147]. However, the project still faces significant security issues and has not yet obtained the neceesary financing.

Non-OECD Asia

In the IEO2011 Reference case, non-OECD Asia is the only regional grouping that changes from a net exporter to a net importer of natural gas. In fact, with net imports of 7.6 trillion cubic feet in 2035, the region becomes the world's second-largest importing region, behind only OECD Europe. The largest increases in import demand are projected for China and India, which together require imports of 6.0 trillion cubic feet per year in 2035. In 2035, China meets 40 percent of its annual consumption with imported natural gas and India 28 percent (Figure 61).

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To meet its future demand, China is actively pursuing multiple potential sources for natural gas imports. At the end of 2010, China had four LNG import terminals in operation, four under construction, and several more proposed or in various stages of development. The country is currently importing natural gas under long-term contract from four different countries, with no single country signed up to provide more than 37 percent of the total contracted volume. In addition, Chinese companies have signed contracts to increase imports from Australia, Qatar, and Malaysia.

At the same time that China is pursuing multiple sources for LNG imports, it is also pursuing multiple sources for pipeline natural gas imports. China's first natural gas import pipeline, completed in late 2009, transports supplies from Turkmenistan and Kazakhstan. 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 [148]. China and Russia continue to discuss future natural gas pipeline connections between the two countries. In 2009, the heads of the countries reached an agreement envisioning 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.

In the IEO2011 Reference case, India's imports as a share of its total natural gas consumption begin rising several years into the projection. In 2010, import growth remained muted as LNG deliveries continued to account for about 17 percent of overall supplies while new production from the Krishna Godavari Basin was ramped up [149]. Over the long term, India's import requirements are expected to increase as its domestic production fails to keep up with demand, and in 2035 its imports total 1.4 trillion cubic feet. Accordingly, India is expected to continue expanding its LNG import infrastructure. The country currently has three active LNG terminals, and its new Kochi terminal is expected to be completed in 2012. 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 field.

Non-OECD Central and South America

Until 2008, South America's natural gas market was almost entirely self-contained. The lone facility operating in international trade was an LNG liquefaction facility on the island of Trinidad and Tobago. However, natural gas in South America has become increasingly globalized, as several countries have become involved in the LNG value chain. Since beginning operations in late 2008 and 2009, floating LNG regasification facilities in Chile (now an OECD member), Argentina, and Brazil have received LNG supplies fairly consistently over the past 2 years. In 2010 alone, their combined LNG imports totaled 0.3 trillion cubic feet [150]. In addition, the first LNG export project in Andean South America was completed in Pampa Melchorita, Peru, in mid-2010. The plant, which has a capacity to produce up to 0.2 trillion cubic feet per year and is supplied by the Camisea gas field, is expected to provide deliveries to Mexico beginning in 2012 and is already sending cargos to the United States and other destinations in Europe and Asia. Pipeline exports from Bolivia, also in the Andean region, remain more or less flat over the projection period but switch from being directed mainly toward Brazil to being directed mainly toward Argentina in the Southern Cone region (Figure 62).

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Reserves

The reported level of global natural gas reserves has grown by 50 percent over the past 20 years, outpacing the growth in oil reserves over the same period. Natural gas reserve estimates have grown particularly in non-OECD Europe and Eurasia, the Middle East, and the Asia-Pacific region. As of January 1, 2011, proved world natural gas reserves, as reported by Oil & Gas Journal²³ were estimated at 6,675 trillion cubic feet—about 66 trillion cubic feet (about 1 percent) higher than the estimate for 2010.

The largest revision to natural gas reserve estimates for 2011 was made in Egypt. Egypt's estimated natural gas reserves increased by 18.7 trillion cubic feet (3.2 percent) over the 2010 estimate, from 58.5 trillion cubic feet to 77.2 trillion cubic feet. In the Middle East, higher reserve estimates were also reported by Abu Dhabi and Saudi Arabia, with increases of 13.5 trillion cubic feet (6.8 percent) and 12.2 trillion cubic feet (4.6 percent), respectively. Also in the Middle East, Israel, which had recorded a minimal level of reserves previously, increased its estimate by nearly 6 trillion cubic feet, to a total of 7 trillion cubic feet. Several countries reported substantial decreases in reserves: Norway with a loss of 9 trillion cubic feet (12 percent), Qatar with a loss of 3.5 trillion cubic feet (less than 1 percent), and the United Kingdom with a decrease of 1.3 trillion cubic feet (12.3 percent).

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Despite output from this reserve base over the past 30 years, world natural gas reserves have increased since the 1980s by an average of 3.1 percent each year (Figure 63). The growth in reserves has even accelerated slightly since 2000, including a massive increase in 2004 by Qatar (from 508 to 910 trillion cubic feet). In 2010, there were large increases in reported natural gas reserves in Turkmenistan and Australia. In Turkmenistan, estimated reserves increased from 94 trillion cubic feet to 265 trillion cubic feet following reappraisals of the giant South Yolotan-Osman field. In Australia, a change in the governmental reporting system led to an increase of 80 trillion cubic feet to 110 trillion cubic feet.

Current estimates of natural gas reserve levels indicate a large resource base to support growth in markets through 2035. Like reserves for other fossil fuels, natural gas reserves are spread unevenly around the world. Natural gas reserves currently are concentrated in Eurasia and the Middle East, where ratios of reserves to production suggest decades of resource availability. In the OECD countries, however, including many where there are relatively high levels of consumption, ratios of reserves to production currently are significantly lower. The impact of the disparity in these ratios is reflected in the IEO2011 projections for increased international trade in natural gas.

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Almost three-quarters of the world's natural gas reserves are located in the Middle East and Eurasia (Figure 64). Russia, Iran, and Qatar together accounted for about 54 percent of the world's natural gas reserves as of January 1, 2011 (Table 7). Reserves in the rest of the world are distributed fairly evenly on a regional basis. 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 60.2 years [151]. Central and South America has a reserves-to-production ratio of 51.6 years, Russia 82.0 years, and Africa 64.7 years. The Middle East's reserves-to-production ratio exceeds 100 years.