The State Of Natural Gas


Energy Tribune, TX
June 12 2006

This article is a Web compilation of our annual three-part series
on natural gas, which was printed in the three most recent issues of
the Energy Tribune magazine.

The series examines what we consider to be the most important
events and emerging issues in global natural gas today. It includes
installments on the United States, by far the biggest natural gas
market, and current and emerging suppliers, such as Russia, Ukraine,
Europe, Iran and Turkmenistan. We also tackle a few of the sleeper
issues that we think have the potential to affect the future gas
market in profound ways, focusing on Canada, Qatar and Indonesia.

The series is designed to give readers a look back at some of the
most important events in natural gas in the past few years, as well
as a preview of the unfolding developments that will affect the global
market for decades to come.


The long dispute between Russia and Ukraine reached a crescendo on
January 1, 2006, when Gazprom, Russia’s natural gas monopoly, shut
off gas supplies to Ukraine.

This not only created problems for Ukraine, but also launched a storm
throughout vulnerable Western Europe, which gets Russian gas via a
main transit route through Ukraine. The relationship between Russia
and Ukraine will likely be the source of future crises. Ukraine’s
Orange Revolution, which followed the 2004 presidential election that
removed the corrupt Russian darling Viktor Yanukovych and replaced him
with Viktor Yushchenko, was widely viewed as an affront to President
Vladimir Putin. His recentralization of power does not leave much
room for independent-minded former Soviet republics.

The Gazprom fight is just one of several recent confrontations
regarding natural gas. Here are a few others: ~UIn 1997, Gazprom
shocked everybody by importing natural gas from Turkmenistan to
help fulfill its supply contract with the Netherlands, using the
pipelines passing through Ukraine. Gargantuan Russian gas reserves
had been mismanaged or connected improperly, and gas supplies had
to be augmented. Turkmenistan and Russia have had repeated disputes
over the pricing of the natural gas, resulting in a complete halt to
natural gas supplies in 2004.from Turkmenistan.

~UIn 2005, Ukraine contracted to buy 812 Bcf of Russian gas at
$1.41/Mcf, a pittance compared to market price. At the same time,
Russia agreed to pay Ukraine in the future natural gas transit fees
of 7.3 cents per thousand cubic feet per 100 miles, a 47 percent
price increase from 2005.

~UIn late 2005, Gazprom agreed to a sell natural gas to RosUkrEnergo –
ostensibly a Ukrainian company in reality controlled by Gazprom – at
the market price of $6.51/mcf ($230 per thousand cubic meters). The
deal caused an uproar in Ukraine and led to the shutdown January
1, 2006.

~UFour days later, Ukraine signed a five-year agreement to buy 580
Bcf of natural gas from RosUkrEnergo at $2.69/mcf (comprised of less
expensive natural gas from Central Asia).

Some things have become abundantly clear. The Russian natural gas
monopoly is in dire need of modernization, a tall order in Putin’s
Russia. The pipeline routes to Europe will have to grow and diversify
so that European countries are no longer hostage to the whims and
quarrels of their eastern neighbors. The importance of these projects
was accentuated when former German Chancellor Gerhard Schroder signed
on with Gazprom, a move that raised eyebrows throughout the world.

And still there is China, looming as an even larger potential market.

There are plenty of ambitious plans and schemes underway now.

~UThe Shtokman field in the Barents Sea, one of the biggest gas fields
in the world, will be connected directly to Europe through the North
European gas pipeline (NEGP). The only trouble is that there are two
potential routes, one passing through Belarus and Poland, and the
other traversing the Baltic Sea and ultimately on to Britain.

~UThe Yamal Peninsula will be connected to Europe via pipeline,
perhaps hooking up with the Barents to the Europe pipeline corridor.

There has even been talk of ice-breaking LNG tankers that would
connect the field through the frozen Arctic Ocean.

~UIn the east, another giant, the Kovytka natural gas field, could
eventually provide China with natural gas for the next decade via a
proposed pipeline, according to a number of analysts the field will
come online in 2006, when it will begin providing natural gas to
local markets.

United States

The on-again, off-again Alaska natural gas pipeline has been back
in the news. First, a very pessimistic Federal Energy Regulatory
Commission said that further delays on the Alaskan natural gas pipeline
may make the project “less feasible.”

Then, almost by magic, a wishfully optimistic Alaskan government
announced an “agreement” between the state and producers. At issue
was the guaranteed price for the gas at the wellhead and details have
not been announced on the settlement. While the pipeline is referred
to now as a “$20-billion project running 3,500 miles from the North
Slope along the Alaska Highway into Alberta and on to markets in the
U.S. Midwest,” there are many, including the Energy Tribune staff,
who believe the price tag is still drastically underestimated.

The far more logical and advanced-stage Mackenzie River Valley pipeline
is set up to carry up to 1.2 Bcf/d of gas from northern to southern
Canada and the United States by 2008.

The U.S. natural gas transmission network slowed its expansion in
2004. According to the EIA, only six new pipeline systems were placed
in operation in the deepwater Gulf of Mexico, plus the 560-MMcf/d
Cheyenne Plains Pipeline and a 320-MMcf/d expansion of the southern
leg of the El Paso Natural Gas pipeline system.

Phase I of the Columbia Gas System Millennium project, connecting
Canadian natural gas sources with the eastern United States, will be
operational by November 2006.

But by far the most important new activities in natural gas deal
with LNG. Cove Point has expanded to be the country’s largest LNG
accepting facility with a new 2.5 Bcf storage capacity installed
in 2005. Expansions are also underway for the Lake Charles and Elba
Island LNG terminals.

The most substantial action in the United States, and the one that
will shape future prices in profound ways and perhaps even stop the
Alaska natural gas pipeline project, is the one involving new LNG
accepting facilities.

Leading the way is Houston-based Cheniere Energy, with three of the
four large approved permits for LNG terminals in Freeport (1.5 Bcf
per day), Corpus Christi (2.6 Bcf per day), and Sabine Pass (2.6
Bcf per day), all in Texas or on the Texas-Louisiana border. The
fourth permit was awarded to the Sempra Energy Cameron LNG project
in Hackenberry, Louisiana (1.5 Bcf per day). The EIA reports that
Sempra also signed a deal with BP in 2003 to supply Indonesian LNG
to a proposed terminal in Baja California. A floating LNG facility,
the Gulf Gateway Energy Bridge, has already started receiving loads
of LNG, but the volume is considerably smaller (0.5 Bcf per day)
than each of the approved and proposed land-based facilities.

Estimates vary, but a “middle of the road” forecast by the EIA suggests
that by 2015 there will be a gap of about 8 Tcf per year (22 Bcf
per day) between increasing consumption and declining production,
the overwhelming part of which will be satisfied by LNG imports.


Iran is a bona fide superpower in natural gas, all the more so because
its potential has barely been tapped. It is also a complicated case,
as the Iranian government fluctuates from radicalism to radical
extremism. Several countries are currently vying for its energy
riches. And Iran’s nuclear ambitions are the cause of ongoing animosity
with the United States, which is reportedly planning to bomb some of
its nuclear facilities.

Despite the friction over nuclear issues, Iran forges ahead on the
gas front, with plans to develop the huge Pars field (first the south,
then the north); the Khuff reservoir of the Salman oil field; the Zireh
field in Bushehr province; the Homa field in southern Fars province;
the Tabnak in southern Iran; the onshore Nar-Kangan fields; the Aghar
and Dalan fields in Fars province; and the Sarkhoun and Mand fields.

Most of Iran’s attention has focused on the giant South Pars offshore
field, which is being developed in 28 phases. The South Pars is
Iran’s largest energy project, and over $15 billion in investment
has been committed. The participant list is a virtual “Who’s Who”
of the international energy business, including many countries whose
governments are occasionally at odds with Iran.

A sample: ~UPhase 1, developed by Iran’s Petropars, began producing
in late 2004. Gas will be shipped north through a pipeline under
construction by Russian and local contractors. Some of the gas will
be re-injected into mature oil fields, including the giant Ahwaz and
Mansouri ones.

~UIn early 2003, Phases 2 and 3 came online, developed by a consortium
led by French Total and including Malaysia’s Petronas and Russia’s

~UPhases 4 and 5 came online in October 2004 and are being managed
by Italy’s Eni and Petropars.

~UPetropars and Norway’s Statoil are managing Phases 6 through
8. The project is scheduled to come online by 2007, and some of the
gas is slated for injection in the Agha Jari oilfield. NIOC will
be the operator. In May 2003, Iran signed a $1.2-billion deal with
a Japanese-led consortium for an onshore processing facility for
these phases.

~UPhases 9 and 10 are being handled by South Korea’s LG Corp., and are
scheduled to come online in 2007. The deal is valued at $1.6 billion.

~UPhase 11 will be used for LNG and is expected to come online in
2010. Total leads Pars LNG along with NIOC. The company was asked to
provide its final conditions for the $1.2-billion project. China’s
CNPC is seeking a 10 percent stake and India’s ONGC has also expressed
an interest.

~UPhase 12 is called NIOC LNG. Both Eni and Statoil have expressed

~UA Shell-led group, Persian LNG, hopes to handle Phase 13, also
intended to be LNG plus LPG by 2010. This is a $4-billion project,
involving NIOC and Spain’s Repsol and its Argentine subsidiary YPF.

~UPhase 14 is intended for gas-to-liquids development. Both Statoil
and Shell have expressed interest.

~UPhases 15 and 16 were initially awarded early this year to a
consortium led by Norway’s Aker Kvaenerbut; however, apparently the
phases will be re-bid according to an announcement by the Iranians.

The remaining phases have yet to be tendered.

Other deals:

Last year, Iran signed a $1.2-billion contract with a consortium
of two foreign and two domestic companies to gather associated gas,
previously flared or re-injected, from the Nowruz, Soroush, Hendijan,
and Behregansar fields. This is an attempt to monetize “stranded
gas.” In addition, BG and NIOC have plans to develop a $2.2-billion
LNG plant at Bandar Tombak on the Persian Gulf.

Iran has also been quite active in pipelines, starting with a pipeline
to Turkey inaugurated in 2002. However, questions about this deal
remain, primarily because Turkey views itself as a transshipment hub
for gas to Europe instead of a destination for Iranian gas.

Shortly afterward, Greece and Iran signed an agreement to extend the
pipeline from Iran to Turkey into northern Greece.

In 2004, Austria’s OMV signed an agreement with the National Iranian
Gas Export Co. (NIGEC) for a possible $5-billion gas pipeline, dubbed
Nabucco, that will go from Iran through Turkey to Austria. A final
decision on the Nabucco line was supposed to come before the end of
2005, but was delayed because of the Iranian nuclear dispute. Nabucco
is still scheduled for inauguration in 2011.

Embroiled in conflicts with Russia, Ukraine has offered two alternative
routes for Nabucco toward Western Europe. The routes would cross
Armenia, Georgia, and Ukraine. In any case, Iran signed a deal in
2005 to sell up to 1 Tcf per year of natural gas to Ukraine.

There are even more grandiose plans in the works, such as an India
pipeline. Iran and Pakistan have signed an MOU for a possible
1,600-mile, $4-billion gas pipeline from Iran to Pakistan and
potentially, on to India. The idea is to eventually link Iran with
China through pipelines. Despite years of negotiations, the three
countries have not been able to agree on pricing. But there is
widespread belief that the pipeline will be built.

Iran is also flexing its muscles as a regional power with countries
of the former Soviet Union. Armenia and Iran have agreed on a
barter deal whereby Iran will supply Armenia with natural gas and
Armenia will supply Iran with electricity. Iran is also considering
importing natural gas from Azerbaijan and is already importing gas
from Turkmenistan with the first pipeline in Central Asia to bypass
Russia for use in Iran’s north

More important, Iran will figure prominently in the enormous emerging
LNG trade. For starters, Iran plans to build three LNG plants at
Assaluyeh using South Pars gas.

In October 2004, Iran signed what is perhaps the largest energy deal
ever- a $100-billion, 25-year contract with China’s Sinopec to export
LNG to China. The deal also included the construction of a refinery for
natural gas condensates and the development of the Yadavaran oilfield.

Last year, the Gas Authority of India Ltd. (GAIL) and NIGEC signed a
30-year deal for an annual 7.5 million metric tons of LNG starting in
2009 or 2010. NIOC offered Indian companies the chance to participate
in the development of the Yadavaran and Jufeyr oilfields.


Turkmenistan’s energy industry, comprised mostly of natural gas, is
trying to move out from under the weight of its former Soviet master.

This is a formidable task. The only obvious way is to forge diverse
routes through the Caspian region and beyond. This means bypassing
the Russian natural gas pipeline system. Until the late 90s, routes
through Russia were the only means of moving gas, and 2 Tcf of natural
gas was piped through the Central Asia Center gas pipeline.

But in 1997, Russia’s Gazprom cut off Turkmenistan’s access to the
pipeline over – what else? – payment disputes.

The dispute was temporarily resolved and Turkmenistan exports resumed
to both Russia and Ukraine. Turkmenistan and Gazprom agreed to increase
gas shipments to 2 Tcf per year with the potential to increase the
annual volume to 3.5 Tcf. Also, Ukraine signed an agreement with
Turkmenistan for gas shipped through Russia. The deals are supposed
to last through 2006.

We already mentioned the pipeline to Iran, the first natural gas
pipeline in Central Asia to bypass Russia. This pipeline could possibly
extend to provide gas to Armenia through Iran.

In the late 90s, Turkmenistan was pushing for the Central Asia Gas
pipeline to carry natural gas through Afghanistan to Pakistan (and
possibly on to India). Unocal got involved but the project was killed
ostensibly because of the war in Afghanistan. After the removal
of the Taliban regime, Presidents Karzai (Afghanistan), Niyazov
(Turkmenistan), and Musharraf (Pakistan) reactivated the idea and a
study is currently in progress.

Turkmenistan is actively pursuing other options, but most of these
deals have fallen apart. MOUs are signed only to be killed or abandoned
once reality sets in. For example, in 1999 Azerbaijan, Georgia, Turkey,
and Turkmenistan signed an agreement to build the Trans-Caspian Gas
Pipeline (TCGP) from Turkmenistan, through Azerbaijan and Georgia,
to Turkey. But the 1,020-mile TCGP now lies dormant.

Nothing is more ambitious than the project contemplated by ExxonMobil,
Japan’s Mitsubishi, and China’s CNPC for the construction of the
world’s longest natural gas pipeline from Turkmenistan to the Chinese
coast. The pipeline would eventually extend to Japan. Don’t hold your
breath on this one.

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Just four or five years ago, U.S. gas supply forecasts invariably
predicted that Canada, the main source for imported gas, would
continue providing its share. The conventional logic was that, if
U.S. demand were to increase by 2 percent, Canadian imports would
increase accordingly. If any one source of U.S. gas, e.g., shallow
offshore, were to lag behind (as it did then), logic dictated that
Canadian gas would step in to fill the void. This assumption was,
of course, preposterous, and recent voices have said so unambiguously.

Analysts now believe that Canadian natural gas production has
already peaked at 18 Bcf/d, and that production from the Western
Canada Sedimentary Basin (WCSB), which today provides 14 Bcf/d,
will decline to 9 Bcf/d by 2020 and to 6 Bcf/d by 2024.

Production in the WCSB has already shifted from Alberta toward new
fields in British Columbia, where recent estimates suggest there are
recoverable reserves of almost 45 Tcf of natural gas.

In the maritime provinces of eastern Canada, there has been
substantial recent activity. Major natural gas production started in
Nova Scotia in 1999, and that is where much of current activity is
concentrated. Offshore fields in Newfoundland are expected to come
online late this year or early next year. Canada’s eastern provinces
are bringing in natural gas production at a very opportune time.

No Canadian project is more anticipated than the venture that will
bring arctic gas from the Mackenzie Delta region. The gas is slated
to start flowing by 2010 if the Mackenzie gas pipeline is completed
on schedule. But it will take more than one pipeline to make up for
declining production in the WCSB. Even the wildest estimates for the
development of the Mackenzie region do not have production/pipeline
capacities exceeding 5 Bcf/d.

There are two potential problems facing Canadian arctic gas projects
that may prevent them from replenishing Canadian needs (and,
by extension, the needs of the U.S.). First, there will be major
competition for this gas among the heavy oil producers in Alberta and
Saskatchewan. Ironically, production of Canadian oil also requires
consumption of natural gas for thermal recovery and processing.

Second, the attractiveness of arctic pipelines (including the rival
Prudhoe Bay gas pipeline schemes) will clearly be affected by LNG

Petro-Canada and TransCanada are constructing the 500-MMcf/d LNG
terminal at Gros Cacouna in Quebec, and in 2004 Petro-Canada signed a
deal with Russia’s Gazprom to provide LNG for the terminal from the
giant Shtokman field. Other LNG plans in eastern Canada, if built,
will provide 4 Bcf/d of LNG by 2008.

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It is a quirk of geology that Qatar, a small Middle Eastern country
with no oil production to speak of, contains 910 Tcf of proven natural
gas reserves, third only to Russia and Iran. Qatar’s offshore North
Field is the largest natural gas field in the world. The country has
other relatively large fields, but none comes close to the size of
the North Field. Qatar is an obvious source of LNG, and two consortia
are already exporting LNG, with many new additions on the way.

Qatargas is a joint-venture between Qatar Petroleum (65 percent),
Total (10 percent), ExxonMobil (10 percent), Mitsui (7.5 percent) and
Marubeni (7.5 percent), and launched its first shipment of LNG to Japan
in 1999. Qatargas LNG operates three trains, with a total capacity
of 9.2 million metric tons per year (1.3 Bcf/d.) Qatar Petroleum and
ExxonMobil dominate Rasgas, Qatar’s second LNG consortium. Rasgas has
four LNG trains that make up a total of 13.2 million metric tons per
year (about 1.9 Bcf/d). A fifth LNG train is scheduled for completion
in 2007.

Qatar Petroleum and ExxonMobil agreed in 2003 to proceed with RasGas
II, scheduled for two massive LNG trains that will each provide 7.8
million metric tons per year, for a total of 15.6. These will be
the largest LNG trains in the world. The trains will come online in
2008 or 2009, after which massive quantities of LNG are slated to be
exported to the United States.

Qatar Petroleum and ConocoPhillips have signed a deal for Qatargas III,
a project that will produce 7.5 million metric tons per year, beginning
in 2009. Qatargas IV is a project involving Shell and is expected
to come online in 2009 or 2010. Both Qatargas ventures will provide
LNG to the U.S. market. Meanwhile, Qatar continues to export gas to
Japan and Korea, and has recently added India as a future client.

Qatar’s push into gas-to-liquids continues. This month, Qatar Petroleum
(a 51 percent owner) and the South African industrial giant Sasol
will inaugurate their Oryx GTL plant, which is slated to produce
34,000 bpd of GTL, primarily diesel. QP, Sasol, and Chevron are now
planning to triple the size of Oryx to more than 1000 bpd.

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Indonesia’s fortune is the exact opposite of Qatar’s. The country
has gone from being the world leader in LNG, when Japan and South
Korea were its main customers, to suffering a rapidly declining market
share. In fact, Indonesia cannot even meet its contractual obligations
these days.

It was bound to happen. A country with a population of about 250
million and economic growth of more than five percent annually needs
energy, and although Indonesia has long been an exporter of petroleum
and natural gas, its domestic needs are catching up. Theoretically,
Indonesia shouldn’t even be a member of OPEC because it has become
a net importer. For the last two years, the country’s LNG-exporting
facilities in Arun, in the troubled Aceh province have been operating
below capacity because Indonesia cannot maintain the required
production for export.

BP may be Indonesia’s only salvation. The company’s Tangguh project,
in Papua province, is supposed to reverse the trend in Indonesia’s
declining LNG fortunes. The project will involve two trains with
a total capacity of 6.6 million tons per year by 2008, and there
are plans to double the capacity at a later time. Contracts have
already been signed with China’s Fujian Province and South Korea’s
POSCO industries.

For maps and tables: