Chapter 3 - Natural Gas
| In the IEO2009 reference case, natural gas consumption in the non-OECD
countries grows more than twice as fast as in the OECD countries. Production
increases in the non-OECD region account for more than 80 percent of the
growth in world production from 2006 to 2030. |
Worldwide, total natural gas consumption increases by an average of 1.6
percent per year in the IEO2009 reference case, from 104 trillion cubic
feet in 2006 to 153 trillion cubic feet in 2030 (Figure 33). With world
oil prices assumed to return to previous high levels after 2012 and remain
high through the end of the projection, consumers opt for the comparatively
less expensive natural gas for their energy needs whenever possible. In
addition, because natural gas produces less carbon dioxide when it is burned
than does either coal or petroleum, governments implementing national or
regional plans to reduce greenhouse gas emissions may encourage its use
to displace other fossil fuels.
Natural gas remains a key energy source for industrial sector uses and
electricity generation throughout the projection. The industrial sector
currently consumes more natural gas than any other end-use sector and is
expected to continue that trend through 2030, when 40 percent of world
natural gas consumption is projected to be used for industrial purposes.
In particular, new petrochemical plants are expected to rely increasingly
on natural gas as a feedstock—particularly in the Middle East, where major
oil producers, working to maximize revenues from oil exports, turn to natural
gas for domestic uses.
In the electric power sector, natural gas is an attractive choice for new
generating plants because of its relative fuel efficiency and low carbon
dioxide intensity. Electricity generation accounts for 35 percent of the
world’s total natural gas consumption in 2030, up from 32 percent in 2006.
In 2006, OECD member countries consumed 52 trillion cubic feet of natural
gas and non-OECD countries consumed 53 trillion cubic feet, surpassing
OECD gas consumption for the first time since the fall of the Soviet Union
in 1991. In the IEO2009 reference case, natural gas consumption in the
non-OECD countries grows more than twice as fast as consumption in the
OECD countries, with 2.2 percent average annual growth from 2006 to 2030
for non-OECD countries, compared with an average of 0.9 percent for the
OECD countries. The non-OECD countries account for 74 percent of the total
world increment in natural gas consumption over the projection period,
and the non-OECD share of total world natural gas consumption increases
from 50 percent in 2006 to 58 percent in 2030.
The OECD countries accounted for 38 percent of the world’s total natural
gas production and 50 percent of natural gas consumption in 2006, making
them dependent on imports from non-OECD sources for 25 percent of their
total consumption. In 2030, the OECD countries account for 31 percent of
production and 42 percent of consumption, with their dependence on non-OECD
natural gas only slightly higher than in 2006, at 27 percent. In the non-OECD
regions, net exports grow more slowly than total production. In 2030, 17
percent of non-OECD production is consumed in OECD countries, down from
19 percent in 2006.
World Natural Gas Demand
OECD Countries
In the IEO2009 reference case, natural gas consumption in North America
increases by an average of 0.8 percent per year from 2006 to 2030 (Figure
34). In the United States—the world’s largest natural gas consumer—consumption
in most of the end-use sectors increases slowly through 2030. Natural gas
consumption in the U.S. electric power sector, however, increases rapidly
from 2006 through 2025 in response to generators’ concerns about the potential
for new legislation limiting greenhouse gas
emissions. Those concerns are addressed in the reference case by the addition
of a risk premium on new carbon-intensive coal-fired generating capacity,
which stimulates investment in less carbon-intensive natural-gas-fired
capacity. In addition, the capital costs for new natural gas power plants
are lower than those for nuclear and renewable alternatives.
After 2025, the growth in U.S. natural gas consumption for electricity
generation is slowed by rising natural gas prices, growing generation from
renewables, and the introduction of clean coal-fired capacity. As a result,
natural-gas-fired electricity generation in 2030 is 94 percent of the 2025
peak level. With the other end-use sectors showing slow but steady growth
in consumption, total U.S. demand for natural gas in 2030 is 2.7 trillion
cubic feet above the 2006 total of 21.7 trillion cubic feet.15
Canada’s total natural gas consumption increases steadily, by 1.5 percent
per year, in the reference case, from 3.3 trillion cubic feet in 2006 to
4.7 trillion cubic feet in 2030. The strongest growth is in the industrial
sector, averaging 1.8 percent per year, and in the electric power sector,
averaging 1.3 percent per year. The rapid growth
projected for Canada’s industrial natural gas consumption is based in large
part on the expectation that purchased natural gas will be consumed in
increasing quantities for mining of the country’s oil sands deposits. In
2006, an estimated 12 percent of Canada’s total natural gas consumption
was used for oil sands production; in 2030, that share could reach 22 percent
of the country’s total gas use.16
In Mexico, more than 90 percent of natural gas consumption occurs in the
industrial and electricity generation sectors combined. Although growth
is projected in all sectors, the share of total consumption accounted for
by the country’s industrial and electric power sectors continues to increase
through 2030. The strongest growth is projected for the electricity generation
sector, at an average annual rate of 4.1 percent, with consumption increasing
almost threefold from 2006 to 2030, while natural gas use in the industrial
sector grows by 1.8 percent per year. In 2006, the amount of natural gas
consumed for electricity generation in Mexico was about one-half the amount
consumed in the industrial sector; in 2030, it is expected to be nearly
equal to consumption in the industrial sector.
Natural gas consumption in OECD Europe grows by a modest 1.0 percent per
year on average, from 19.2 trillion cubic feet in 2006 to 21.5 trillion
cubic feet in 2015 and 24.1 trillion cubic feet in 2030—mostly as a result
of increasing use for electricity generation. Many nations in OECD Europe
have made commitments to reduce carbon dioxide emissions, bolstering the
incentive for governments to encourage natural gas use in place of other
fossil fuels. In addition, given the long lead times and high costs associated
with constructing new nuclear capacity, as well as the expected retirement
of some existing nuclear facilities, natural gas and renewable energy sources
become the fuels of choice for new generating capacity. In the IEO2009 reference case, natural gas is the second fastest-growing source of energy
for electricity generation in the region, at 2.0 percent per year, as compared
with renewables at 3.4 percent per year. Natural gas use in the region’s
electric power sector increases from 5.8 trillion cubic feet in 2006 to
7.7 trillion cubic feet in 2015 and 9.3 trillion cubic feet in 2030.
Natural gas consumption in OECD Asia grows on average by 1.0 percent per
year from 2006 to 2030. Japan,
South Korea, and Australia/New Zealand are projected to add less than 1
trillion cubic feet of natural gas demand each between 2006 and 2030 (Figure
35). Total natural gas consumption for the region as a whole increases
from 5.5 trillion cubic feet in 2006 to 7.0 trillion cubic feet in 2030.
In Japan, the electric power sector is projected to remain the main consumer
of natural gas, accounting for 64 percent of the country’s total natural
gas consumption in 2030, up from 59 percent in 2006. In Australia/New Zealand,
the industrial sector accounted for the largest share of natural gas use
in 2006, at 56 percent of the total; in 2030, its share falls to 50 percent.
Over the same period, the electric power sector share increases from 28
percent to 35 percent. South Korea’s natural gas use is concentrated in
the electric power and residential sectors, with each accounting for approximately
one-third of the country’s total natural gas consumption in 2006; however,
the electric power sector share is projected to grow to 47 percent in 2030.
Non-OECD Countries
Russia is second only to the United States in total natural gas consumption,
with demand totaling 16.6 trillion cubic feet in 2006 and representing
55 percent of Russia’s total energy consumption. In the IEO2009 reference
case, natural gas consumption in Russia grows by 0.9 percent per year on
average, and its share of total energy consumption increases to 56 percent
in 2030, outpacing growth in liquid fuels and coal consumption. Throughout
the projection, the industrial and electric power sectors each account
for around one-third of total natural gas consumption in Russia, about
the same as in 2006.
Natural gas consumption in the other countries of non-OECD Europe and Eurasia
grows at an average annual rate of 1.3 percent, from 8.8 trillion cubic
feet in 2006 to 12.0 trillion cubic feet in 2030 (Figure 36). In Turkmenistan,
domestic consumers have received natural gas for free since 1993. Not surprisingly,
then, Turkmenistan has had the fastest consumption growth in the region,
averaging 16.1 percent annually from 2000 to 2006, as compared with 6.3
percent per year for the rest of Central Asia and Azerbaijan over the same
period, and 0.1 percent per year for the rest of non-OECD Europe and Eurasia,
excluding Russia. Outside Central Asia and Azerbaijan, most of the rest
of the region relies on imports of natural gas from Russia to meet significant
portions of their demand, and they have seen natural gas prices rise as
Russia has endeavored to bring most of its export prices up to the levels
paid by importing countries in OECD Europe.
Non-OECD Asia, which accounted for 9 percent of the world’s total consumption
of natural gas in 2006, shows the most rapid growth in natural gas use
in the reference case and accounts for 31 percent of the total increase
in world natural gas consumption from 2006 to 2030. Natural gas consumption
in non-OECD Asia increases from 9.4 trillion cubic feet in 2006 to 24.5
trillion cubic feet in 2030, expanding by 4.1 percent per year on average
over the projection period (Figure 37).
In both China and India, natural gas currently is a minor fuel in the overall
energy mix, representing only 3 percent and 8 percent, respectively, of
total primary energy consumption in 2006. In the IEO2009 reference case,
natural gas consumption rises rapidly in both countries, growing by 5.2
percent per year in China and 4.2 percent per year in India, on average
from 2006 to 2030.
In the rest of the non-OECD Asia countries, natural gas already is a prominent
fuel in the energy mix, representing 23 percent of total primary energy
consumption in 2006. Their combined annual consumption of natural gas increases
more slowly than in either China or India, averaging 3.6-percent growth
per year. With consumption starting from a much larger base, however, the
rest of non-OECD Asia adds more natural gas consumption over the projection
period than do China and India combined. Together, China and India are
projected to consume 7.1 trillion cubic feet more natural gas in 2030 than
in 2006, as compared with an increase of 8.1 trillion cubic feet for the
rest of non-OECD Asia.
Natural gas consumption grows at average annual rates of 2.0 percent in
the Middle East and 3.2 percent in Africa from 2006 to 2030. There is very
little infrastructure on the continent for intraregional trade of natural
gas, and Algeria, Nigeria, Egypt, and Libya—the major African producers—also
are the major consumers. The four countries plus South Africa and Tunisia,
accounted for 94 percent of Africa’s natural gas consumption in 2006. Intraregional
infrastructure also is limited in the Middle East, although both Dubai
(in the United Arab Emirates) and Kuwait have plans to begin importing
LNG to meet peak summer demands for natural gas [1].
In Central and South America, natural gas is the fastest-growing energy
source in the reference case, with demand increasing on average by 2.4
percent per year, from 4.5 trillion cubic feet in 2006 to 8.1 trillion
cubic feet in 2030. For Brazil, the region’s largest economy, natural gas
consumption more than doubles—from 0.7 trillion cubic feet in 2006 to 1.8
trillion cubic feet in 2030. 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 reduce the use
of more expensive oil-fired generation often used to supplement electricity
supply.
Although pipeline infrastructure is in place to move natural gas from Argentina
to Brazil, Chile, and Uruguay and from Bolivia to Argentina and Brazil,
recent concerns about the security of supply have spurred development of
LNG regasification terminals in the importing nations. Specifically, Argentina
became the region’s first LNG importer in May 2008; Chile has plans to
add two LNG regasification plants by 2010; a single terminal has been proposed
for Uruguay; and Brazil plans to open three LNG terminals in the next several
years [2].
World Natural Gas Production
In order to meet the demand growth projected in the IEO2009 reference case,
the world’s natural gas producers will need to increase supplies by 48
trillion cubic feet between 2006 and 2030. Much of the increase in supply
is expected to come from non-OECD countries, which in the reference case
account for 84 percent of the total increase in world natural gas production
from 2006 to 2030. Non-OECD natural gas production grows by an average
2.1 percent per year in the reference case, from 65 trillion cubic feet
in 2006 to 106 trillion cubic feet in 2030 (Table 5), while OECD production
grows by only 0.8 percent per year, from 40 trillion cubic feet to 47 trillion
cubic feet.
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 2006 to 2030 in the reference case and more than one-fifth of the
total increment in world natural gas production. Currently, there are four
major natural gas producers in the Middle East: Iran, Saudi Arabia, Qatar,
and the United Arab Emirates, which together accounted for 83 percent of
the natural gas produced in the Middle East in 2006. Each of the four countries
has announced plans to expand natural gas production in order to meet the
expected increase in regional demand and/or to supply markets outside the
region.
In Saudi Arabia there has been a concerted effort to increase natural gas
production specifically for domestic consumption. At present, Saudi Arabia
produces most of its natural gas from associated oil and natural gas fields;
however, there may be fluctuations in oil production when Saudi Arabia
balances global supply and demand, which also will affect the production
of natural gas.
To reduce the dependence of its natural gas production on oil production,
Saudi Arabia has begun efforts to increase production from nonassociated
natural gas fields. To that end, in 2003 private investment for natural
gas exploration projects was invited at four sites in the Rub al-Khali
desert [3]. Although 27 exploration wells are to be drilled at the sites
by the end of 2009, results have not been encouraging thus far, and relatively
low fixed prices set by Saudi Arabia for the natural gas have made the
projects less attractive to foreign participants [4]. The Saudi national
oil company, Saudi Aramco, on the other hand, has made several nonassociated
natural gas finds near existing oil fields, some of which are expected
to begin producing in the near term, including the Karan natural gas project,
scheduled to begin producing 1.8 billion cubic feet per day in 2012.
Iran has the world’s second-largest reserves of natural gas, after Russia,
and currently is the Middle East’s largest natural gas producer. Political
barriers—including U.S. sanctions and international concerns about the
country’s nuclear power ambitions—have lowered interest in foreign direct
investment in the country’s natural gas sector. The largest natural gas
development project in Iran is the offshore South Pars field, discovered
in 1990, which is estimated to contain between 350 and 490 trillion cubic
feet of natural gas reserves [5]. Located 62 miles offshore, South Pars
has a 28-phase development plan spanning 20 years, with each phase set
to produce more than 1 billion cubic feet per day. Iran has set a goal
to raise marketed natural gas production to between 9 and 10 trillion cubic
feet per year by 2010, more than double its 2006 marketed production of
4.4 trillion cubic feet. That goal may be difficult to achieve, however,
without attracting substantial foreign investment in the near term.
The world’s second-largest regional increase in natural gas production
is expected in non-OECD Europe and Eurasia, which includes Russia. In the
reference case, natural gas production in non-OECD Europe and Eurasia increases
from 30.0 trillion cubic feet in 2006 to 40.3 trillion cubic feet in 2030.
Russia remains the region’s most important natural gas producer, providing
the single largest increment in production, from 23.2 trillion cubic feet
in 2006 to 31.3 trillion cubic feet in 2030.
Russia’s Yamal Peninsula in northwestern Siberia has ample natural gas
resources and should provide a major increase in Russian production over
the long term. In 2008, state-owned Gazprom began construction of a trunk
pipeline to connect Bovanenkovo field, the largest on the Yamal peninsula,
to existing pipeline infrastructure. Also in 2008, Gazprom drilled the
first production well in the Bovanenkovo field [6]. Gazprom intends to
increase production from the Yamal peninsula to 12.7 trillion cubic feet
by 2030, both to meet domestic demand for natural gas and to double the
size of its exports from current levels.
Developing new sources of natural gas is a priority for Gazprom, given
that production at its three largest fields (Yamburg, Urengoy, and Medvezh’ye)
is in decline [7]. There is concern that the global economic recession
may reduce both domestic and export demand for natural gas in the short
run and dampen investment in Russia’s natural gas sector. In the IEO2009 reference case, however, investment delays are not expected to hinder the
growth of Russian supplies.
Two other major natural gas projects also are underway in Russia: one to
develop the resources around Sakhalin Island on the country’s east coast
and another to develop the Shtokman field, off its western Arctic coast.
The Sakhalin-1 project began supplying modest amounts of natural gas to
domestic consumers in 2007. Production volumes from the first development
phase are limited, however, until all the parties involved can agree on
how the natural gas should be exported. Production from the second development
phase will be exported as LNG, beginning in the first half of 2009, with
supplies from the Sakhalin-2 LNG facility expected to reach its total capacity
of 9.6 million metric tons in 2010 [8]. The Shtokman natural gas and condensate
field in the Barents Sea is officially scheduled to begin producing 840
billion cubic feet of natural gas in 2013 (shipped via pipeline), with
additional supplies for LNG anticipated beginning in 2014 [9]. That schedule
may, however, prove to be overly ambitious.
Substantial growth in natural gas production also is projected for Africa,
increasing from 6.6 trillion cubic feet in 2006 to 9.6 trillion cubic feet
in 2015 and 13.9 trillion cubic feet in 2030. Currently, more than 85 percent
of Africa’s natural gas is produced in Algeria, Egypt, and Nigeria, which
together accounted for 81 percent of Africa’s proved natural gas reserves
as of January 1, 2009, with a combined total of 402 trillion cubic feet
[10].
Nigeria has the most attractive geology for natural gas exploration and
development and, in terms of reserves, the greatest potential to increase
production. With a slightly larger quantity of proved reserves than Algeria,
Nigeria produced only about one-third the amount of natural gas produced
by Algeria in 20006. Security concerns and uncertainty over access terms
are expected to inhibit resource development in Nigeria, however, and its
contribution to the expected increase in Africa’s natural gas production
is more modest than its reserves and geology would imply. The rest of the
production increase is spread over a number of countries, including Algeria,
Egypt, Libya and Angola.
In the IEO2009 reference case, non-OECD Asia’s natural gas production increases
by 8.8 trillion cubic feet from 2006 to 2030, with 2.2 trillion cubic feet
of the increment coming from China, 1.3 trillion cubic feet from India,
and 5.3 trillion cubic feet from the rest of non-OECD Asia. The strongest
growth in natural gas production in recent years has come from China, with
increases averaging 13.6 percent per year from 2000 to 2006. China is poised
to become the region’s largest natural gas producer, as production has
declined in recent years in Indonesia and the increases in China’s production
have outpaced those from the region’s other major producers, Malaysia,
Pakistan, and India.
Natural gas production from the OECD nations increases by 7.8 trillion
cubic feet from 2006 to 2030 in the reference case. The largest regional
increases are projected for the United States, at 5.3 trillion cubic feet,
and Australia/New Zealand, at 2.8 trillion cubic feet. The projected production
increases for the two regions are offset in part by production declines
in Canada and OECD Europe, where existing conventional natural gas fields
are in decline.
From 2006 to 2030, total U.S. natural gas production per year increases
by more than 5 trillion cubic feet, even as onshore lower 48 conventional
production (from smaller and deeper deposits) continues to taper off. Unconventional
natural gas is the largest contributor to the growth in U.S. production,
as rising prices and improvements in drilling technology provide the economic
incentives necessary for exploitation of more costly resources. Unconventional
natural gas production increases from 47 percent of the U.S. total in 2006
to 56 percent in 2030.
Natural gas in tight sand formations is the largest source of unconventional
production, accounting for 30 percent of total U.S. production in 2030,
and production from shale formations is the fastest-growing source, with
an assumed 267 trillion cubic feet of undiscovered technically recoverable
resources. Production of natural gas from shales increases from 1.1 trillion
cubic feet in 2006 to 4.2 trillion cubic feet, or 18 percent of total U.S.
production, in 2030. The expected growth in natural gas production from
shales is far from certain, however, and continued exploration is needed
to provide additional information on the resource potential.
Natural gas production in Australia/New Zealand grows from 1.7 trillion
cubic feet in 2006 to 4.4 trillion cubic feet in 2030 in the reference
case, at an average rate of 4.2 percent per year—the strongest growth in
natural gas production among the OECD countries. In 2006, Australia’s production
was far larger than New Zealand’s, at 1.5 trillion cubic feet and 0.1 trillion
cubic feet, respectively. Australia continues to dominate production in
the region throughout the projection, given its large resource base and
plans for expanding production of natural gas both for domestic use and
for export.
The Carnarvon Basin—located off the Northwest shelf in Western Australia—is
one of the country’s most important natural gas producing areas, holding
an estimated 62 trillion cubic feet of probable reserves. In addition,
new development in the deepwater Timor Sea at Browse Basin is expected
to bring even more natural gas to market in the future [11]. There also
has been considerable interest in developing Australia’s coalbed methane
resources, especially as a fuel for LNG production. Five projects to produce
coalbed methane for conversion to LNG currently are planned or under development
in Australia, with LNG production from the first project (the 1.5 million
metric ton Fisherman’s Landing project in Queensland) scheduled to begin
in late 2012 [12].
Natural Gas Import Dependence
OECD Countries
OECD North America is largely a self-contained market for natural gas.
Although North America imported 631 billion cubic feet of natural gas from
other regions in 2006 through six LNG regasification terminals, including
one in Mexico and five in the United States, those imports accounted for
only 2 percent of its total natural gas consumption. Three new regasification
terminals became operational during 2007 and 2008, including the first
on North America’s Pacific Coast; and six more were being commissioned
or were under construction at the beginning of 2009, including the first
regasification terminal in Canada.
With North America’s reliance on imports of natural gas projected to grow
somewhat in the short to mid-term (Figure 38), imports rise to 6 percent
as a share of total natural gas consumption in the region before falling
back to 4 percent in 2030. An expected decline in U.S. demand for imports
in the later years of the projection is the result of an increase in domestic
production from unconventional sources and improvements in clean coal technology
that allow for increased generation from coal-fired power plants, reducing
demand for natural gas in the power sector. Consequently, U.S. dependence
on natural gas imports declines from 17 percent in 2006 to 3 percent in
2030, as Canada’s production and exports decline, and as domestic production
from shale and other unconventional sources increases. Mexico, on the other
hand, becomes more dependent on imports through most of the projection
period, as production and investment in its natural gas sector fail to
keep up with consumption growth. The shortfall in Mexico’s domestic natural
gas supply is expected to be balanced by pipeline imports from the United
States and imports of LNG.
The dependence of OECD Europe on imported natural gas continues to increase
in the reference case, as demand grows modestly and indigenous natural
gas production declines. In 2006, 44 percent of OECD Europe’s total natural
gas demand was met with imports from outside the region. Imports from two
countries, Russia and Algeria, accounted for more than 30 percent of the
region’s total consumption. In 2030, net imports make up 57 percent of
total natural gas consumption. OECD Europe’s import dependence is an area
of concern, particularly because natural gas exporters have signed several
cooperation agreements (see "Gas Exporting Countries Forum: What is GECF and What is the Objective?), and parts of the region have
experienced supply disruptions during three of the past four winters.
In January 2006, Russia’s Gazprom cut natural gas supplies to Ukraine.
Natural gas prices, pipeline transit fees, and debts owed by Ukraine all
were at issue. The conflict was resolved three days later [13]. In January
2008, Turkmenistan cut natural gas exports to Iran, and Iran reacted by
cutting exports to Turkey to make up for the lost imports from Turkmenistan.
In turn, Turkey cut its exports of natural gas (originally imported from
Azerbaijan) to Greece to make up for the lost imports from Iran. Subsequently,
Gazprom increased its exports of natural gas to Turkey.
More recently, in January 2009, another dispute with Ukraine again led
Russia to curtail natural gas exports to Ukraine [14]. The basic issues
were the same as in 2006: natural gas prices, pipeline transit fees, and
debts owed by Ukraine. In this instance, however, rather than lasting three
days, the dispute lasted almost three weeks. On January 1, Russia reduced
natural gas deliveries to the Ukrainian border, but some gas continued
to flow across Ukraine to downstream customers. On January 7, all natural
gas exports via Ukraine stopped, as Russia and Ukraine blamed each other
for shutting down the pipelines. Natural gas flows were not resumed until
January 20, when Russia and Ukraine finally reached an agreement on prices
and pipeline transit fees [15].
In OECD Asia, Japan and South Korea continue to be almost entirely dependent
on LNG imports for natural gas supplies. The two countries continue to
be major players in LNG markets (with Japan representing 41 percent of
global LNG imports in 2006 and South Korea 15 percent) despite consuming
relatively small amounts of natural gas on a global scale (representing
3 and 1 percent, respectively, of world consumption in 2006). South Korea
could begin receiving natural gas supplies by pipeline from Russia sometime
after 2015, but Japan and South Korea are expected to remain influential
in LNG markets even as growth in global production of LNG outpaces their
import demand.
Much of the growth in Australia’s natural gas production is expected to
support planned or proposed LNG export projects, although it is possible
that some projects and the related production increases could be delayed.
Pluto LNG, currently under construction in Australia, is one of the few
natural gas liquefaction projects for which a final investment decision
has been made in the past few years [16]. Rising costs for liquefaction
projects have led many companies around the world to delay project commitments,
and decisions on other projects could be delayed as a result of the current
global financial crisis and the impending global oversupply of LNG. Projects
in Australia face additional hurdles, including a Western Australia policy
that requires new export projects to reserve 15 percent of production for
domestic use. Also, LNG liquefaction plants are significant contributors
to Australia’s carbon dioxide emissions, and new obligations under Australia’s
Carbon Pollution Reduction Scheme, enacted in December 2008 (and to commence
in 2010), may make some liquefaction projects uneconomical [17].
Non-OECD Countries
In the near term, Russia’s net exports of natural gas as a percentage of
production are projected to decline, as the global economic slowdown affects
demand in Europe and, in turn, Russia’s pipeline exports to European countries.
In the longer-term, the reference case assumes that the necessary investments
will be made to develop Russia’s vast natural gas resources, allowing it
to continue supplying increasing volumes of natural gas to its neighbors.
Exports, which represented 28 percent of Russia’s natural gas production
in 2006, are projected to fall to 26 percent in 2010 before growing to
more than 30 percent in 2030. Production of natural gas in Russia grows
by 1.3 percent per year on average in the IEO2009 reference case, from
23 trillion cubic feet in 2006 to 31 trillion cubic feet in 2030.
Natural gas production in the Middle East and in Africa is expected to
become oriented more toward exports as the Medgaz pipeline from Algeria
to Spain comes on line and new liquefaction capacity comes on line in Qatar,
Algeria, Yemen, and Angola. Both the Middle East and Africa are projected
to increase production by more than 40 percent from 2006 to 2015. In the
Middle East, net exports as a share of total natural gas production grow
from 14 percent in 2006 to 24 percent in 2015. In Africa, exports grow
from 55 percent of production in 2006 to 57 percent in 2010, before falling
back to 56 percent in 2015. After 2015, the pace of export developments
in the two regions slows, and with their domestic demand continuing to grow,
the rate of increase in the export share of production in the Middle East
slows, while the export share of Africa’s natural gas production declines.
India’s dependence on imported LNG is projected to be reduced in the short
term, when new natural gas production from the Krishna Godavari Basin comes
on line. Accordingly, the import share of India’s natural gas consumption
falls from 20 percent in 2006 to 13 percent in 2010 (Figure 39). Much of
India’s current production, however, comes from more mature natural gas
fields that are beginning to decline, and in 2030 India is projected to
be dependent on imports for more than 30 percent of its total natural gas
consumption. Pipelines to bring natural gas from Iran, Central Asia, or
Myanmar have been discussed in the past, but to date no firm agreements
have been reached.
China’s dependence on natural gas imports grows throughout the projection
period. Although new supplies from Sichuan province are expected to come
on line in the short term, and the country’s total domestic production
of natural gas increases by 3.1 percent per year on average from 2006 to
2030 in the reference case, production growth cannot keep up with demand
growth. In 2030, China could be dependent on imports for more than one-third
of its total natural gas consumption. To help meet its growing need for
imports, China opened its first LNG regasification facility in 2006 at
Guangdong [18]. Shanghai LNG was to be the second regasification terminal
in China, with startup in early 2009; however, a fatal accident at the
facility during pipeline testing has delayed its startup. Instead, Fujian
LNG, which is expected to begin operation in mid-2009, will be China’s
second LNG receiving terminal [19]. Additionally, the first imports of
natural gas into China by pipeline are expected by 2011, when a new pipeline
from Turkmenistan via Kazakhstan is to be inaugurated [20].
In 2006, the rest of non-OECD Asia (excluding China and India) was a net
exporter of natural gas. Three countries—Indonesia, Malaysia, and Brunei—currently
have LNG export facilities. There also have been several proposals made
to build LNG liquefaction facilities in Papua New Guinea. Although Indonesia’s
LNG exports peaked in 1999 at about 30 million metric tons (1.4 trillion
cubic feet of natural gas) and had declined to about 23 million metric
tons (1.1 trillion cubic feet of natural gas) in 2006, a new liquefaction
facility, Tangguh LNG, is scheduled to come on line in 2009, temporarily
reversing the decline in the country’s total LNG exports. Production from
the two LNG facilities currently in operation in Indonesia is expected
to continue declining [21].
In this grouping (non-OECD Asia excluding China and India), only one country,
Taiwan, currently has an LNG import terminal, although there have been
proposals to build regasification terminals in Singapore, Pakistan, Thailand,
the Philippines, and Indonesia. In 2006, net exports equaled 24 percent
of total production in the group of countries, but with domestic demand
continuing to grow, imports are projected to account for 6 percent of their
total natural gas consumption in 2030 in the IEO2009 reference case.
On a percentage basis, Brazil’s natural gas production shows the most rapid
growth in the reference case. Starting from 0.3 trillion cubic feet in
2006, Brazil’s production is projected to grow by an average of 6.6 percent
per year to 2030. In 2006, Brazil depended on imports from Bolivia for
nearly one-half of its natural gas consumption; in 2030, its import dependence
is less than 10 percent of total consumption. In the short to mid-term,
however, Brazil is planning to increase imports. Two LNG import terminals
are expected to start up in 2009, and there are plans to build at least
one more regasification terminal in the country [22]. At the same time,
Brazil is also discussing the possibility of building an LNG liquefaction
facility that would allow it to supply its own regasification terminals
throughout the country or to export small volumes to neighboring countries.
World Natural Gas Reserves
Historically, world natural gas reserves have generally trended upward
(Figure 40). As of January 1, 2009, proved world natural gas reserves,
as reported by Oil & Gas Journal,17 were estimated at 6,254 trillion cubic
feet— 69 trillion cubic feet higher than the estimate of 6,186 trillion
cubic feet for 2008 [23]. Reserves have remained relatively flat since
2004, despite growing demand for natural gas, implying that, thus far,
producers have been able to continue replenishing reserves successfully
with new resources over time.
The largest increases in reported natural gas reserves in 2009 were for
Iran and the United States. Iran added an estimated 43 trillion cubic feet
(a 5-percent increase over 2008 proved reserves) and the United States
added 27 trillion cubic feet (a 13-percent increase). There were smaller,
but still substantial, reported increases in reserves in Indonesia, Kuwait,
Venezuela, and Libya. Reserves in Indonesia and Kuwait both rose by 13
percent—with Indonesia’s reserves increasing by 12 trillion cubic feet
and Kuwait’s by 7 trillion cubic feet. Venezuela added nearly 5 trillion
cubic feet of reserves (a 3-percent increase), and Libya added 4 trillion
cubic feet (a 9-percent increase).
Much of the increase in U.S. natural gas reserves results from expanded
knowledge and exploration of shale resources. Outside the United States
there has been almost no exploration of shale resources, and correspondingly
little is known about the resource potential in other countries. Technologies
that have greatly improved the economics of U.S. shale plays, including
horizontal drilling and hydraulic fracturing, probably can be adapted to
resource plays in other parts of the world. These technologies may, for
instance, be applied in Europe before too long. A few North American energy
companies have begun to explore potential shale plays in Central and Western
Europe. At the same time, a few European energy companies have invested
in North American shale plays. As the technologies are applied in other
regions, economically recoverable natural gas reserves in the rest of the
world are likely to increase, as they have in the United States.
The largest reported declines in natural gas reserves in 2009 were in Kazakhstan
(a decrease of 15 trillion cubic feet) and Qatar (13 trillion cubic feet).
The Kazakhstan decline represents a 15-percent drop, although at 85 trillion
cubic feet, the country still holds significant proved reserves. Given
the vast resources in Qatar (now about 892 trillion cubic feet), the 2009
decrease amounts to only a 1-percent decline in the country’s total proved
reserves. Turkmenistan also reported a fairly substantial decrease in reserves
of 6 trillion cubic feet (6 percent). Germany and the United Kingdom reported
smaller decreases, but they represent more significant shares of the two
countries’ total reserves. For Germany, the reported decrease of 3 trillion
cubic feet amounts to a 31-percent reduction in proved reserves. For the
United Kingdom, the decrease of 2 trillion cubic feet amounts to a 17-percent
reduction.
Almost three-quarters of the world’s natural gas reserves are located in
the Middle East and Eurasia (Figure 41). Russia, Iran, and Qatar together
accounted for about 57 percent of the world’s natural gas reserves as of
January 1, 2009 (Table 6).
Despite high rates of increase in natural gas consumption, particularly
over the past decade, reserves-to-production ratios for most regions are
substantial. Worldwide, the reserves-to-production ratio is estimated at
63 years [24]. By region, the highest ratios are about 48 years for Central
and South America, 78 years for Russia, 79 years for Africa, and more than
100 years for the Middle East.
Notes and Sources
References
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