Featured report on the realities of Iraq's power supply shortfall. With New Iraq Development Group reported-on being part of the solution. NID Group's chairman, engineer Mr. Ghazi shares some facts on Iraqi's market needs.

1. Leigh Elston
After years of failed planning in the electric-
ity sector in Iraq, the power shortfall in the
south of the country is a source of mounting
political tension.
Over the course of 2011, the electricity
ministry was shrouded by accusations of
bureaucracy, incompetency and a lack of
transparency, with electricity minister Raad
Shalal being asked to resign in August.
The slow development of the power sec-
tor looks particularly acute when electricity
supply in the south is compared to that of the
Kurdistan Region of Iraq (KRI) in the north.
According to the October 2011 quarterly
report from the Special Inspector General
for Iraq Reconstruction, electricity genera-
tion was up by just 14% in the south since
2008, producing a maximum of eight hours of
electricity per day. In comparison, electricity
generation in the KRI had increased by 581%
since 2008 and generators were able to pro-
vide 24 hours of uninterrupted electricity sup-
ply in the third quarter of 2011. While power
infrastructure in the KRI was less damaged by
the war, the Kurdistan Regional Government
(KRG) has proved “better organised and a
better regulator”, than its southern counter-
part, Michelle Karavias, a senior infrastruc-
ture analyst at Business Monitor International
told Interfax.
However, Iraqi Kurdistan covers a far
smaller area than southern Iraq and is a lot
safer to operate in. And “they’ve had a 12-year
head-start to get their act together. Kurdistan
was liberated 10 years before the rest of the
country”, Dr Zuhair al-Naher, the London-
based spokesperson for the ruling Dawa Party
in Iraq told Interfax.
Furthermore, the KRG has “a lot more
control; there are only two parties there who
have basically divided up the sector, whereas
there are many political parties in the south so
decision making is much harder,” he said.
But, he adds, the bureaucracy and political
wrangling that has paralysed the development
of the industry in southern Iraq is now being
addressed, “because the electricity sector
is a priority as far as the prime minister is
concerned. He has weekly or fortnightly meet-
ings with the energy committee (a specialist
committee of the ministers of oil, electricity,
finance and other related ministries and the
head of the advisory committee). Bureau-
cracy in Iraq is a reality that does slow things
down, but a lot of tension and a lot of pres-
sure is being put to ease those bureaucratic
hindrances.”
Escalating security situation
The rise in sectarian violence in the south and
the rapid unravelling of the fragile political al-
liance in Baghdad is unlikely to encourage new
foreign investment in the power sector, or speed
development on the ground of already long-
delayed projects.
“The moment that United States troops left,
the failings of the sectarian system put in place
by the US were exposed... Sunnis feel they are
being marginalised by a Shia administration that
is being backed by Iran. So there is dangerous
polarisation along sectarian lines,” Gerald Butt,
editor of the weekly politics and energy brief
of consultancy MENA Prospect, told Interfax.
“President Talabani is trying to bring all political
parties to a national conference, but without any
success. If such efforts fail, then armed groups
on either side will increasingly take the law
into their own hands, opening the possibility
of civil war.”
Security has long been an issue for companies
operating in Iraq, and although a resurgence
of sectarian fighting may hinder the develop-
ment and procurement of materials for projects,
Karavias doubts it will prompt companies to
withdraw. “Turkish developers in »6
Inside Natural Gas Daily
Electricity capacity coming online in Iraq,
Megawatts
Source: Business Monitor InternationalCapacity, MW
0
1,000
2,000
3,000
4,000
5,000
201420132012
4,410 4,428
4,000
Iraq braces to meet power supply shortfall
Temperature drop causes UK gas
prices to hit record high
CNPC and Sinopec to expand CTG
transmission from Xinjiang
EU infrastructure deal unlikely
before end of 2012
LNG imports are Colombia’s
priority
Producers feel heat in Argentina as
subsidies fail again
Why Russia’s elections matter
MET increase to impact Gazprom
profits in Russia
India’s falling output drives east
coast LNG plans
2
8
3
9
10
4
5
7
www.interfaxenergy.com
Interfax Information Services Group
© 2012 Interfax Ltd
Global natural gas news and analysis Volume 2 Issue 24 ■ Monday, 6 February 2012

2. Natural Gas Daily
6 February 2012 | 2Europe
Temperature drop causes UK gas prices
to hit record high
UK prompt spot gas prices traded at their
highest level since 2006, as freezing tempera-
tures, snow and ice covered the country over
the weekend. The unseasonably cold weather is
expected to continue for another seven days.
UK NBP spot gas prices rose steadily since
last Tuesday with same-day prices trading
by Monday afternoon up to 87.50 pence per
therm (p/th) and prices for next-day (Tuesday
7 February) delivery trading at 85.50 p/th.
“The UK price rise is in reaction to the
recent cold weather as well as moving up in
line with higher European prices. Although the
UK does not rely on Russian export supplies,
the UK gas market has seen the firmer prices
traded in European impacted by the Russian
export shortfall,” Andrew Horstead, a Utilyx
analyst told Interfax.
The UK relies on gas deliveries from
Norway via the Langeled pipeline which has
not seen any recent disruption in UK deliver-
ies. However, any disruption in Norwegian gas
deliveries could result in a price hike, Horstead
added.
According to the UK’s daily National Grid
gas data, at 10 am, on Monday morning (6
February) the National Grid forecasted de-
mand at 394.4 million cubic metres (MMcm),
compared to average seasonal demand of
328.6 MMcm.
The shortfall in UK gas supply is being met
from UK storage facilities and LNG imports.
Rough, the largest gas storage facility in the
UK, located 18 miles off the coast of Yorkshire,
is supplying 46 MMcm/d, and can hold up to
3.3 billion cubic metres. Britain holds less gas
storage than most large European countries, up
to 5 bcm, which is estimated to meet about two
weeks of UK gas consumption under normal
conditions.
Graham McQuarrie, National Grid press
officer, told Interfax that daily gas supplies
amounting to 67 MMcm were being drawn
from the UK’s three LNG import terminals, Isle
of Grain, South Hook and Dragon.
Horstead added there has been concern
over how much LNG the UK will receive, as
many LNG cargoes in the past six months have
sold to higher priced destinations such as Asia.
Qatar supplied the UK with 85% of its LNG be-
tween January and November 2011. As the UK
moves to become more reliant on LNG imports
in the next 5-10 years, gas prices are likely to
become more volatile.
UK regulator OFGEM’s Chief Executive
Alistair Buchanan told journalists at a gas
forum last week that the UK was concerned
about security of gas supply and said the
Department of Energy and Climate Change
requested for OFGEM to review the UK’s
medium to long-term gas supply, and had
expressed concern over the UK’s dependence
on Qatar for LNG.
Contact editorial at editorial.news@interfax.co.uk
Interfax Staff
Supply & demand | UK
Premier Oil has stopped drill-
ing at the East Fyne appraisal
well in the UK’s central North
Sea because of the thickness
of the oil-bearing sand, the
company said on Monday.
Drilling encountered 11 feet
(3.4 m) of gas-bearing sand
and 2.4 m of oil-bearing sand.
Italy’s offshore Adriatic LNG
regasification terminal at
Rovigo is running on lower
volumes because ships are
unable to dock due to rough
seas, Dow Jones reported on
Monday. Ships have been
unable to dock at the terminal
since Friday. The terminal,
owned by ExxonMobil, Edison
and Qatar Petroleum, usually
imports 20 MMcm/d.
Development of the 8 bcm/y
Galsi pipeline between Algeria
and Italy has been bogged
down by economic and techni-
cal problems that are blocking
construction, Algeria’s El
Khabar reported on Monday,
citing Energy and Mines
Minister Youcef Yousi. “With
regard to the Galsi project,
the partners are waiting for
technical and economic
conditions to be present and
also to obtain administra-
tive authorisation in Italy to
go ahead with the project,”
Yousi said. The project was
expected to begin operat-
ing in mid-2014. Italy already
receives 30-35% of its gas
imports from Algeria via the
Trans-Mediterranean link.
Europe in brief
Natural Gas Daily is published daily except during the last
week of December by Interfax Europe Ltd. ISSN 2048-4534.
Copyright ©2012 Interfax Europe Ltd. All rights reserved. No
part of this report may be reproduced or transmitted in any
form, whether electronic, mechanical or any other means
without the prior permission of Interfax. In any case of repro-
duction, a reference to Interfax must be made.
All the information and comment contained in this report is be-
lieved to be correct at the time of publication. Interfax accepts
no responsibility or liability for its completeness or accuracy.
INTERFAX EUROPE LTD.
19-21 Great Tower Street, London EC3R 5AQ, UK
Tel: +44 (0) 20 3004 6200
Fax: +44 (0) 20 7283 1332
Web: www.interfaxenergy.com
General enquiries: customer.service@interfax.co.uk
Editorial enquiries: editorial.news@interfax.co.uk
CONTRIBUTORS
Africa (Nairobi): Jessica Hatcher
Australia (Melbourne): Sally Bogle
Azerbaijan (Baku): Anar Azizov, Nigar Abbasova
Belgium (Brussels): Andreas Walstad (EU Policy),
Danila Bochkarev
China (Shanghai): Dave Lore (bureau chief), James Burbridge,
Hang Dong, Colin Shek, Tang Tian, Victor Wang; (Beijing) Rainy
Lee, Li Xin; (Hong Kong) Robert Sullivan
Germany (Berlin): Joshua Posaner
India (New Delhi): Eric Randolph, Siddharth Srivastava
Kazakhstan (Almaty): Elena Preobrazhenskaya
Latin America (Santiago): Anatoly Kurmanaev
North America (New York): Conway Irwin
Russia (Moscow): Alexey Novikov, Svetlana Savateeva
Ukraine (Kiev): Alexey Egorov, Roman Ivanchenko
EDITORIAL
Chief Editor Therese Robinson
+44 (0)20 3004 6221
therese.robinson@interfax.co.uk
Senior Reporter James Batty
+44 (0)20 3004 6218
james.batty@interfax.co.uk
Senior Reporter Sophie Davies
+44 (0)20 3004 6215
sophie.davies@interfax.co.uk
Senior Reporter Leigh Elston
+44 (0)20 3004 6220
leigh.elston@interfax.co.uk
Senior Reporter Andreas Walstad
andreas.walstad@interfax.co.uk
Reporter Christopher Noon
+44 (0)20 3004 6219
chris.noon@interfax.co.uk
Reporter Sara Stefanini
+44 (0)20 3004 6216
sara.stefanini@interfax.co.uk
Junior Reporter James Byrne
+44 (0)20 3004 6208
james.byrne@interfax.co.uk
Junior Reporter Ahmed Mehdi
+44 (0)20 3004 6209
ahmed.mehdi@interfax.co.uk
PRODUCTION
Chief Sub-editor Rhys Timson
Sub-editor Doug Kitson
Web & Production Editor Joseph Williams
SALES
Subscriptions customer.service@interfax.co.uk
Sales Manager, Energy John Bulmer
+44 (0)20 3004 6202
john.bulmer@interfax.co.uk
Sales Manager, Energy Marwan Galal
+44 (0)20 3004 6204
marwan.galal@interfax.co.uk
Sales Manager, Energy (Asia) Cynthia Wong
+852 2537 2262
cynthia.wong@interfax-news.com

3. EU infrastructure deal unlikely before end of 2012
An agreement on pan-European
energy infrastructure develop-
ment priorities is not likely before
the end of 2012 due to diverging
views among EU member states
on several key points, according
to a note circulated by the Danish
EU Presidency in preparation for
the 14 February meeting of the EU
energy ministers.
The document seen by Energy
Monitor says that agreement be-
tween the European Parliament
and the Council on a draft regula-
tion outlining energy infrastructure
development priorities up to 2020
“should preferably be reached
before the end of 2012”.
This would enable it to enter into
force in early 2013, which would
in turn allow for the establishment
of the first EU-wide list of priority
infrastructure projects – the so-
called projects of common interest
(PCI) – by the end of July 2013, as
proposed in the draft regulation by
the European Commission.
Taking stock of the first round of
discussions in the Council’s energy
working group, the Presidency
admited that talk at this stage is still
devoted to the “clarification of dif-
ferent provisions and the interplay
between them”.
“Many delegations are still
studying the text and therefore
maintain scrutiny reservations,”
according to the document.
“Some delegations also wonder
whether [the PCI selection process]
could realistically be completed by
31 July 2013, as proposed by the
Commission.”
Based on previous discussions,
the Presidency has identified a list
of concerns regarding the proposed
criteria for selecting PCIs; simplify-
ing project authorisation proce-
dures; the role of national and local
regulatory bodies in authorising
PCIs; and financing issues.
Projects of common interest
While most member states support
the general idea of tasking regional
groups with the selection of PCIs,
several issues remain to be resolved
with regards to the exact role,
establishment, composition and
the functioning of such groups, the
Presidency noted.
“On the proposed selection
process, some delegations would
like to make it shorter, simpler
and less bureaucratic, while others
stated that some phases of the
process should be lengthened,” the
document said.
Several countries would like to
see a greater role for member states
in selecting PCIs. The Commission,
on the other hand, would like to
take the process out of government
hands as much as possible, for fear
of ending up with a list of several
hundred projects, as is the case
under the current TEN-E project
support framework.
Philip Lowe, director general
for energy at the Commission,
voiced this concern recently, at a
conference in Brussels organised
by the Council of European Energy
Regulators (CEER).
“Realistically, can the EU have
some 600 projects of common
interests?” he asked the audience,
while debating possible ways of
solving the problem of underin-
vestment in European generation
capacities and energy transport
infrastructure.
According to the Presidency
note, several member states have
called for additional criteria to de-
fine what is meant in the proposed
regulation by “market failure”,
“isolated market”, “security of sup-
ply” and “industrial interest” – all
meant to be key conditions in the
PCI selection process.
There is also doubt as to whether
only projects listed in the Ten-
Year Network Development Plans
(TYNDP) – which are regularly
updated by the European organi-
sations of transmission system
operators for electricity and gas
(ENTSOE and ENTSOG) – should
be the selection base for PCIs.
“Some member states oppose cer-
tain criteria, such as the condition
that a project should appear on the
Union-wide TYNDP,” the note says.
Commission officials have also
acknowledged recently that the
TYNDPs may not be such a reliable
source for project selection after all.
At the CEER conference last
week, Jean-Arnold Vinois, head
of the energy policy and security
of supply unit at the European
Commission, noted that more than
50% of the priority interconnection
projects identified at the end of last
year by a high-level regional group
in Central and Eastern Europe are
not included in the TYNDPs.
“This was meant to be a model
example of how the PCIs should
be selected, and over half of the
projects are not in the TYNDPs,”
Vinois told the conference.
Permit granting
During discussions in the Council
on the granting of permits for PCIs,
concerns were expressed about
the need to maintain the neces-
sary safeguards for citizens and the
environment, as well as to respect
the role of local, regional and
national authorities, the Presidency
note said.
Several delegations argued that –
in view of the Commission’s impact
assessment attached to the draft
regulation – some of the provisions
outlined in Article 8 were dispro-
portionate. “In particular, it was
underlined that a one-size-fits-all
approach might not work equally
well in all member states due to
their diversity, and that many
changes required in national legis-
lation and at the level of national,
local and regional administration
were not proportional to the aims,
which could be achieved by more
general requirements on member
states,” said the document.
On the organisation of the
permit granting process, its dura-
tion and implementation, several
delegations requested longer time-
frames than the three-year time cap
proposed by the Commission. They
also wanted more flexibility within
the proposed timeframe, as regards
both the timing of the phases
proposed and the procedure to be
followed by the member state.
Contact editorial at editorial.news@
interfax.co.uk
The European Parliament hopes for draft energy developement regulations by 2013. (PA)
EU Policy & Regulation
A round-up of the latest policy initiatives in Brussels
Supplied by Energy Monitor

4. Natural Gas Daily
6 February 2012 | 4Russia & the Caspian
As a result of domestic pressure following allegations of
widespread fraud in parliamentary elections last year,
Russian energy officials are focusing on domestic needs
as presidential elections draw near.
Thousands of protestors braved temperatures as low
as -19C in Moscow this weekend to rally against Prime
Minister Vladimir Putin. Saturday’s turnout – estimated
by organisers at 120,000 and by officials at 36,000 –
defied expectations that the protest movement would
run out of steam.
As the Kremlin’s strategists vow to engineer a road-
map for political survival ahead of the March presiden-
tial elections, Putin used the weekend to task Gazprom
with the challenge of prioritising domestic demand.
In his meeting with Vice Premier Igor Sechin and
Deputy Chairmen of the Gazprom Management
Committee Alexander Medvedev and Andrei Kruglov,
Putin said: “The main task of the energy sector in
general and Gazprom in particular is to satisfy Russian
domestic demand. That is, to supply consumers in
the Russian Federation. That is the primary task,”
he said.
Putin’s comments follow a week in which European
spot gas prices surged due to supply shortfalls in Poland,
Austria, Italy, Hungary, Bulgaria and Greece. According
to the European Commission, Austria received 30% less
gas than ordered, Italy received 24% less, and Poland
8% less.
According to Kruglov, Gazprom is meeting its con-
tract obligations, despite the increased volume of orders.
“We see that the volume of orders has increased. We
have an approved schedule of gas deliveries to Western
Europe,” Kruglov said.
Kruglov also mentioned that in Ukraine, Gazprom
supplied more gas than stipulated by its contract obliga-
tions. “In Ukraine last week, there was an overuse of gas
compared to the contract,” he said.
Last week, Ukraine took between 150 million and
170 million cubic metres per day (MMcm/d) instead of
the 135 MMcm/d stipulated by the contract, he said.
Gazprom confident
Commenting on the situation within Russia, Kruglov
struck an altogether more confident note on Gazprom’s
ability to meet soaring domestic demand during the
cold snap. According to Kruglov, Gazprom companies
are producing 1.6 billion cubic metres per day of gas.
Kruglov reported that, in contrast with last year,
production is up by roughly 300-400 MMcm. “We are
also taking out 630 million from underground storage
daily,” he said.
The amount of gas being taken by utilities provid-
ers is up by 200 MMcm from a year ago, Kruglov said.
“We are satisfying all requests, and there have been no
cut-offs. We are working with industrial enterprises in
accordance with the contracts,” he added.
Supplies stretched
Despite Kruglov’s comments however, domestic
supply in the country is stretching the country’s
gas balance.
According to Interfax data, for the past 10 days,
gas supplies to Russian consumers have exceeded the
threshold (1.82 bcm/d) that was set by last year’s supply
quota enshrined in the Law Schedule No.1.
Schedule No.1 stipulates restricting gas supplies
to industrial consumers in favour of maximising the
supply to household consumers, and the housing
and public utilities sectors. With gas supplies on
1 February 2012 reaching unprecedented highs of
2.04 bcm, last year’s imposition of a gas supply cap
has been broken.
For Russia’s power sector, gas supplies to Russia’s
power companies also peaked this year with
702 MMcm/d compared to 637 MMcm/d last year,
according to Interfax figures.
According to Igor Yurgens, chairman of the Institute
for Contemporary Development and first vice-president
of Renaissance Capital Investment Group, while Putin
is likely headed for victory in March, “he will reassume
the presidency with lower support and be on the defen-
sive,” he told Interfax.
Whether Russia’s energy sector will be able to balance
an increasing domestic focus with its contractual obliga-
tions in Europe remains to be seen as further pressure
is set to mount in the coming months – both on the
streets of Moscow and the industrial heartland of
the country.
Contact Ahmed at amhed.mehdi@interfax.co.uk
Why Russia’s elections matter
A major part of last week’s European gas supply shortfall was due to Gazprom’s focus on Russia’s domestic needs. With political
pressures on the streets of Moscow, a strategy is needed to satisfy these demands. Ahmed Mehdi and Alexey Novikov report
Total gas supply in Russia including supplies for technical needs*
MMcm
1,500
1,700
1,900
2,100
2,300
2,500
04-Feb30-Jan25 Jan20 Jan15 Jan10 Jan5 Jan1 Jan
Source: Interfax
2012 2011
*Pipelines and underground storage facilities
“The main task of the
energy sector in
general and Gazprom
in particular is to satisfy
Russian domestic
demand”
Russian Prime Minister Vladimir
Putin

5. Russia & the Caspian
Gas transit via Belarus 44.2 bcm in 2011 – Gazprom
A total of 44.2 billion cubic metres
of Russian gas was transported
via Belarus in 2011, Gazprom told
Interfax.
The company said in a press
release following a board meeting
that “31.3 bcm of Russian gas was
transported via the republic in
2011, 21% of all exports to Europe.”
The Belarusian Energy Ministry
has said the transit of Russian gas
fell by 3.1% to 43.2 bcm in 2010.
Therefore, using the 44.2 bcm figure
the amount of Russian gas trans-
ported via Belarus grew by 2.3% in
2011 compared with 2010.
Gas supply to Belarus for
internal consumption was 20.6
bcm in 2011, Gazprom said. “It was
noted at the meeting that Belarus is
the second-biggest market among
former Soviet republics for Russian
gas. Belarus received 20.6 bcm of
gas in 2011 – 29% of overall sales to
former Solvet Union countries,” the
company said in the press release.
Belarus bought 21.6 bcm of gas
in 2011, 22.7% more than in 2009,
so gas imports from Russia fell by
4.6% last year.
Gazprom also said that, in the
future, it will conduct an audit of
the technical condition of Belt-
ransgaz plant and equipment; draft
proposals to improve the operation
of gas transport and storage facili-
ties; and put together development
programmes for the company for
the next three and 10 years, as
well as a general plan for gas
supplies to Belarus.
It also said that the paperwork
needed to change Beltransgaz’s
name to OJSC Gazprom Transgaz
Belarus has been prepared.
The governments of Russia
and Belarus signed an agreement
on 25 November 2011 regarding
procedures for setting prices for gas
supplies to Belarus and transporta-
tion of gas via pipelines in Belarus,
as well as an agreement on the
terms of the sale of shares in Belt-
ransgaz and the company’s future
operations.
At the same time, contracts were
signed for gas supplies to Belarus
and transportation through its
territory in 2012-2014, as well as a
purchase-sale agreement for 50%
of shares in Beltransgaz. Gazprom,
which had already acquired 50%
of Beltransgaz between 2007 and
2010, thus became the sole owner
of the Belarusian company.
At the beginning of 2011,
Belarusian officials said that the
amount of gas transshipments
through the country would not de-
crease in coming years, and would
remain at about 43 bcm.
However, on 8 November 2011
Gazprom launched the Nord
Stream pipeline, which bypasses
Belarus. The pipeline now carries
about 27 million cubic metres of
gas per day, or the annual equiva-
lent of 9 bcm.
With the launch of Nord
Stream, Gazprom has reduced gas
shipments via Yamal-Europe. The
Yamal-Europe pipeline carried
1.755 bcm of gas to Germany in the
period from 1 January to 5 Febru-
ary 2012, down by 37% from 2.773
bcm in the same period of 2011.
Contact editorial at editorial.news@
interfax.co.uk
Interfax staff
supply & demand | belarus
MET increase to impact Gazprom profits in Russia
This year’s increase in the mineral
extraction tax (MET) on gas will
reduce Gazprom’s profits on Russia’s
domestic market, the state-con-
trolled company said in a statement
following a board of directors meet-
ing on Monday.
On 1 July, regulated prices on
Russia’s gas market are expected
to grow by 15%, which will boost
Gazprom’s revenue by 50 billion
rubles ($1.66 billion) for 2012.
However, a rise in the MET will
dent Gazprom’s expenditure by
Alexey Novikov
policy & regulation | Russia
Natural gas production tax
(Gas MET)
Gazprom and its subsidaries
2012 $16.88/Mcm
2013 $19.30/Mcm
2014 $20.63/Mcm
Independent gas producers
2012 $8.32/Mcm
2013 $8.79/Mcm
2014 $9.22/Mcm
Source: Troika Dialog
0
25
50
75
100
125
150
175
200
225
250
1Q15*
1Q14*
1Q13*
1Q12*
1Q11
1Q10
4Q09
3Q09
2Q09
1Q09
4Q08
3Q08
2Q08
1Q08
4Q07
3Q07
2Q07
1Q07
4Q06
3Q06
2Q06
1Q06
4Q05
3Q05
2Q05
1Q05
4Q04
3Q04
2Q04
1Q04
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
RR/MMcm
Historical and forecasted regulated price increases for Russian domestic gas
%changeinregulatedprice
* According to the new Russian government decree on 22 February 2011, full liberalisation is targeted for 2015 (a one year delay from
previous plan); 2012 tariff increase based on preliminary draft proposal for 5% increase 1 January 2011 and 9.5% in April, or 12.5%
average increase for the year
Source: Novatek
Increase in regulated price
Average regulated price
23.4%
18.8% 10.6%
15%
25% 5%
7% 7%
6.2%
15%
15%
12.5%
15%
15%
??%
$16.88/Mcm, in 2013 it will pay
$19.3/Mcm, and in 2014 it will pay
$20.63/Mcm. For independent gas
producers, the rate will be $8.32/
Mcm this year, $8.79 next year and
$9.22 in 2014.
Gazprom’s board of directors or-
dered management to lobby for tax
parity with independent producers
as well as differentiating the MET
for gas from condensate in order to
boost production at new fields.
According to the statement, in
order to implement gas projects
in the east of the country, it would
be expedient to provide discounts
comparable to those granted to
oil producers, the statement said.
Most importantly, the MET for gas
production on the Far Eastern shelf
and in Yakutia should be cancelled
for the projects’ pay-off periods.
Contact editorial at editorial.news@
interfax.co.uk
$3.78 billion, according to a com-
pany statement.
“In 2012, the company will pay
to the budget not only all of its ad-
ditional revenue earned as a result
of an increase in the wholesale price
on the domestic market, but also 64
billion rubles [$2.12 billion] of its
profit,” the statement said.
Gazprom supplied gas to the
domestic market at a loss during
the period 2000-2008.
In 2009, the company was able to
recover its costs and achieve a low
level of profitability in sales. “This
profit subsequently grew, but its
level is still low and does not allow
for forming sources to ensure the
reliable development of Russia’s gas
sector,” the company said.
For Gazprom, the MET increase
will lead to additional tax payments
of $14.59 billion compared to 2011,
it said.
Last year, Gazprom paid a MET
of $7.86 per thousand cubic metres
(Mcm) of gas. This year it will pay
Natural Gas Daily
6 February 2012 | 5

6. particular have been very active
in the power sector and I can’t
see them winding that activity
down unless they see a drastic
escalation in violence. The op-
portunities are very attractive in
Iraq, especially as a lot of these
companies are struggling in other
areas they operate in. The con-
tract opportunities are quite slim
at the moment in the electricity
sector in general, so the opportu-
nity Iraq presents may outweigh
the security challenge. However,
if there was a civil war that would
of course put projects on hold,”
she said.
For now the violence is mainly
confined to the cities, with neither
oil and gas developers, nor power
companies, pinpointed as targets.
Trailing behind demand
Power demand in southern Iraq
is around 10,000-14,000 mega-
watts. Although southern Iraq’s
nameplate generation capacity is
around 16,500 MW, much of the
equipment is outdated and plants
are operating at only 50% of their
capacity, according to BMI data.
While output reached a record
high of 6,990 MW in July 2011
– an improvement on the 4,500
MW generated in July 2008 – it’s
still significantly under the 14,000
MW peak demand.
As a temporary measure to
ease the supply gap last summer,
the government struck a deal
with private power operators,
offering them free fuel provided
they capped charges for custom-
ers. Under this agreement, private
generators
were able to meet around 30-40%
of peak demand. The government
will likely repeat the arrangement
this summer.
As a further short-term fix, the
ministry contracted South Korea’s
STX Heavy Industries to install
nine 100 MW diesel-fired units
across the country last year. The
units are due online in June.
However, the major, long-
term improvements will come
following the start-up of the
1,400-2,000 MW gas-fired power
plants, awarded to international
developers over the last two
years. Around 4,410 MW of
new gas-fired capacity is due to
start-up in 2012 and 4,428 MW
in 2013, according to BMI data.
However, this is dependent on
plant construction running on
time – few companies are willing
to comment on the status of their
projects – and availability of gas
supply.
“There are plans to add an-
other 35% [of generation capac-
ity] in the coming three years,”
Ghazi Faisal, chairman engineer
of the New Iraq Develop Group, a
consortium of engineers formed
in 2003 to help in the recon-
struction of Iraq, told Interfax.
However, demand is expected
to hit 25,000 MW by 2020, he
added. The current generation
capacity will need, therefore, to
increase by more than 257% over
the next eight years to keep pace
with the rise.
Aside from the plants them-
selves, supporting pipeline and
storage infrastructure will need to
be brought online in tandem with
the start-up of gas fields to supply
the generators, as well as new
transmission and distribution
lines to bring the power to con-
sumers. Developing supporting
power infrastructure has perhaps,
“been neglected by the govern-
ment and is now one of the big-
gest constraints to bringing new
capacity online”, said Karavias.
Rehabilitating and expanding
the gas and power grid would
require billions of dollars of
investment, and, although the
government has the cash as a
result of increased oil exports, “it’s
a case of dispersing it correctly;
getting it to the right ministries
and to the right projects. That’s
been a major issue; although the
government assigns the money,
they never quite get round to
spending it”, she added.
“Iraqi oil revenues jumped by
60% to $83 billion in 2011, yet
improved earnings have failed to
translate for the most part into
tangible improvements for Iraq’s
population,” Gerald Butt said.
“Power rationing still hinders eco-
nomic activity and undermines
Iraqis’ satisfaction with their
government. Central government
and legislative institutions are
largely frozen by
the sectarian conflict at the heart
of government.”
Over the last six months the
electricity ministry has appeared
to place a higher priority on
ensuring electricity distribution
is more reliable and fair. For ex-
ample, the ministry has drawn up
plans to replace decrepit overhead
transmission lines in Baghdad
with underground lines to protect
them from weather and unau-
thorised interfering, has stepped
up its campaign to stop illegal
tapping from the grid, and has
received bids from companies for
the construction of distribution
control centres in seven provinces
to help monitor the more even
distribution of power and im-
prove the technical performance
of the grid.
The development of support-
ing electricity infrastructure, “is
something that the Ministry of
Electricity is well aware of, as is
the Ministry of Oil. The infra-
structure of both the electricity
and oil sector needs to be im-
proved and a number of contracts
and projects are being awarded to
improve it,” Naher said. The New
Iraq Development Group has, for
example, been contracted to build
several electrical substations for
Siemens, and further contracts
are expected.
Gas supply
Iraq is at least now poised to
ramp up gas production to feed
these plants. The signing of the
Royal Dutch Shell-led Basra Gas
Company (BGC) gas-gathering
agreement in November 2011,
and the preceding approval of
contracts to develop Iraq’s three
major non-associated gas fields,
were major steps towards guaran-
teeing reliable future gas supplies
to the country’s power stations.
Contact Leigh at leigh.elston@interfax.
co.uk
Middle East & Africa
A gas processing facility in Basra province, Iraq. (PA)
Turkmenistan has cut gas
exports to Iran by 50%, from 20
MMcm/d to 10 MMcm/d, Irani-
an mass media have reported.
Meanwhile, Bloomberg quoted
head of National Iranian Gas
Co. Javad Owji as saying that
Turkmenistan has reduced gas
supplies to the country to 6
MMcm/d, which is less than
contracted volumes.
Egyptian gas supplies to Jor-
dan have stopped after a bomb
attack in the north African
country, Jordan’s Minister of
Energy and Mineral Resources
Qutaibah Abu Qura told Petra
news agency on Sunday.
Middle East &
Africa in brief
»Continued from page 1
Natural Gas Daily
6 February 2012 | 6

7. Asia/Pacific
Indian LNG projects. (Interfax)
Canadian Prime Minister
Stephen Harper headed to China
on Monday with the leaders of
several oil and gas majors, in an
effort to strengthen ties with the
Asian heavyweight, The Globe
and Mail reported. Shipping oil
and gas to Asia is “a national
priority” for Canada, Harper has
said.
Work on Indonesia’s Donggi-
Senoro LNG plant in central
Sulawesi is 33% complete and
ahead of schedule, The Jakarta
Post reported on Monday. The
developer, Medco Energi
Internasional, had been aiming
to have the 2.9 mtpa plant 26%
complete by now, with a start-
up expected in late 2014.
Iran has given India’s state-run
Oil and Natural Gas Corp. a
one-month deadline to sign the
contract for the development
of offshore Farzad B gas field in
the Persian Gulf, Iran’s Press TV
reported.
Asia/Pacific in
brief
terminals will need to be built
along India’s east coast.”
India’s east coast has emerged as
a hub of industrial and commercial
activity over the past few years,
thanks in large part to expectations
of strong and prolonged output
from the Krishna Godavari Basin
and Reliance’s D6 Block. About
700 megawatts of new generation
capacity is planned for the region.
The deep-water D6 Block has,
however, disappointed, with its
output in 2011 standing at about
half the anticipated 80 million
cubic metres per day (MMcm/d)
rate (see India’s 2011 gas initiatives
driven by falling output, 3 January
2012).
The country’s total gas output
is about 120 MMcm/d, while de-
mand hovers around 220 MMcm/d
and is expected to more than
double in five years, according to
the petroleum ministry.
The effect of this falling produc-
tion on India’s LNG imports is
already visible, with Petronet’s
regasification volume of 45
MMcm/d between September and
December setting a new record for
the company.
The change has also driven
talks over several new terminals in
the past few months. Along with
Petronet’s Gangavaram project,
three state-run companies are
planning terminals on the east
coast – India Oil Co.’s Ennore
project in Tamil Nadu and the
Bharat Petroleum-Minerals and
Metals Trading Corp. Paradip
facility in Orissa.
In addition, the newly created
BP-Reliance joint venture, India
Gas Solutions, is rumoured to be
looking at setting up as many as
three LNG terminals with a focus
on eastern India, while Reliance
Power and Shell are said to be
in talks about their own east
coast facility.
Meanwhile, GAIL signed an
agreement last month with the
state government of Andhra
Pradesh to set up a $1 billion
import facility at Kakinada or
Vishakapatnam in the state.
“The LNG terminal of 3.5 to
5 mtpa is likely to be the first such
facility on the east coast of the
country,” GAIL said in a statement
in mid-January. The company esti-
mated that its gas import needs will
rise to seven times that of its 2010
level, to 187 MMcm/d by 2015.
Contact Sara at sara.stefanini@interfax.
co.uk
India’s falling output drives east coast LNG plans
Petronet LNG, India’s largest
LNG importer, has decided to
build a third regasification terminal
in an effort to tap into the country’s
fast-growing reliance on im-
ported gas to make up for its falling
domestic output, Chairman GC
Chaturvedi has told Interfax.
The state-owned company
announced in late January that it
had approved plans for a 5 million
ton per annum (mtpa) terminal at
Gangavaram, in the central-eastern
state of Andhra Pradesh. Petronet
has commissioned the French
consultant Tractebel to carry out
a feasibility report on the project,
estimated to cost around INR 45
billion ($917.3 million).
“Overall, we expect to raise
LNG regasification capacity by
three times the current level by
2015-2016,” said Chaturvedi, who
is also secretary of India’s Ministry
of Petroleum and Natural Gas.
Petronet already operates the
Dahej terminal in the north-
western state of Gujarat, which
grew from a capacity of 5 mtpa to
10 mtpa in 2009 and is being
expanded to 15 mtpa. The com-
pany is also building the 5 mtpa
Kochi facility in the south-western
state of Kerala, set to be completed
by July and begin operating by
October.
India has one other opera-
tional LNG terminal, the Total-
Royal Dutch Shell Hazira facility
in Gujarat. State-run companies
GAIL, Maharasthra State Electric-
ity Board and National Thermal
Power Corp. are also building
the Dabhol terminal near Mumbai,
which is scheduled to begin
operating in mid-2012.
But with production from
India’s Krishna Godavari Basin in
the eastern Bay of Bengal declining
significantly, India needs to build
import terminals on the other side
too, Chaturvedi said. “As the local
gas supply is going to fall woefully
short and transporting gas from
the west coast of India is expensive,
Siddharth Srivastava and Sara Stefanini
lng | india
Dahej*
Mundra
Hazira
Kochi*
Dabhol
Ennore
Gangavaram*
Kakinada/Vishakapatham
ParadipINDIA
Operational
Proposed/planning stages
Under construction
*Projects owned by Petronet LNG
Natural Gas Daily
6 February 2012 | 7

8. China
CNPC and Sinopec to expand CTG transmission from Xinjiang
China’s two largest gas produc-
ers will raise their combined
coal-to-gas (CTG) transmission
capacity in the Xinjiang Uyghur
Autonomous Region to 161
billion cubic metres per year
by 2015.
China’s surging demand for
gas has piqued interest in CTG
projects in coal-rich Xinjiang.
The cost of the fossil fuel in
the region is around RMB 150
($23.80) per ton, significantly
lower than prices of $95.20 to
$126.93 per ton in east China,
Zheng Chunlin, an analyst with
AsiaChem Consulting, told Inter-
fax on Monday.
The potential of Xinjiang’s
CTG sector is drawing attention
from non-energy firms as well
as established industry players.
State-owned coal miner Xukuang
Group is constructing a CTG
plant in Tacheng City, while state-
owned coal chemical producers
Henan Coal Chemical Industry
Group and Xuzhou Coal Mining
Group also have CTG projects
underway.
Coal gas will help meet
China’s gas demand, but the
production process requires large
quantities of water and emits
carbon dioxide, Zhou Hongjun,
a professor at the China Univer-
sity of Petroleum, told Interfax
on Monday.
China National Petroleum
Corp. (CNPC), the country’s
largest gas producer, expects to
have 113 bcm of annual CTG
transmission capacity by 2015,
the company announced on
Monday, citing remarks made by
Liang Peng, deputy general man-
ager of CNPC unit Natural Gas &
Pipeline, at an industry meeting
in Xinjiang on Friday.
CNPC will transmit coal gas
produced in Xinjiang via its
West-East Gas Pipeline (WEP)
network, which will have a 257
bcm/y transmission capacity in
the region by 2015.
CNPC plans to invest more
than $15.87 billion on building
five trans-provincial gas pipelines,
eight CTG gathering stations, and
14 CTG branch lines with a total
length of 430 km.
Meanwhile, Sinopec’s CTG
transmission capacity in Xinji-
ang will likely reach 48 bcm/y
by 2015, Liu Yan, director of
Sinopec’s Development Planning
Department, said at the same
meeting. The company agreed to
source coal gas from nine firms
for two cross-country synthetic
natural gas pipelines, Interfax
reported in January.
The nine suppliers together
have a total of 10 CTG projects
planned or under construction in
Xinjiang that will be capable of
producing a combined 50 bcm/y
by 2020.
Contact editorial at editorial.news@
interfax.co.uk
Rainy Lee
Exploration & production
CNPC unit to invest $475 mln in Hebei Province gas project
Huagang City Gas Group,
a unit of China National
Petroleum Corp. (CNPC), has
signed a strategic cooperation
framework agreement for a
gas project in Handan City,
Hebei Province, local media
reported on Monday. Huagang
signed the agreement with the
Handan municipal government
on Friday.
The RMB 3 billion ($475.38
million) project will include a gas
liquefaction plant capable
of processing 2 million cubic me-
tres of gas daily and a 270 km
gas pipeline running from
Jincheng City, Shanxi Province
to Handan, according to a report
in the Handan Daily. Some 50
LNG refilling stations will also
be built, the report said.
In December of 2011, Huagang
Gas agreed to invest $379.13 mil-
lion to build an LNG liquefaction
plant, 50 LNG refilling stations,
three city-gate stations and a
150 km pipeline in Jincheng
City in Shanxi, Interfax previ-
ously reported.
Handan has seven CNG refill-
ing stations, a source with local
refilling station operator Handan
Huaxin Natural Gas Utilisation
told Interfax on Monday.
Huagang Gas plans to build
150 LNG refilling stations during
the 12th Five-Year Plan period
(2011-2015), according to a com-
pany announcement released on
28 December. Huagang plans to
supply the stations with gas from
CNPC’s Jiangsu LNG terminal,
as well as coal-bed methane re-
sources in Shanxi and LNG from
a liquefaction plant in Cangzhou
City, Hebei.
CNPC plans to have more
than 2,000 LNG refilling stations
across China by 2015, Shanghai-
based analyst Han Xiaoqing,
from energy consultancy
C1 Energy, told Interfax on
Monday.
Contact editorial at editorial.news@
interfax.co.uk
Hang Dong
pipelines & storage
China will halve its oil imports
from Iran in March because of
dispute over payments and pric-
es, Reuters reported on Monday
citing industry sources involved
in the deals. China is the largest
remaining buyer of Iranian oil and
has been critical of Western plans
to impose further sanctions on
the country.
China in brief
China’s growing gas demand has increased interest in CTG projects in coal-rich areas
such as the Xinjian Uyghur Autonomous Region. (PA)
Natural Gas Daily
6 February 2012 | 8

9. Natural Gas Daily
6 February 2012 | 9Americas
“Long-term energy
security is the name of
the game for the sector,
and diversification is the
appropriate strategy”
CERA’s Verónica Vázquez
Colombia is likely to enter the global LNG market as a
net importer, despite its parallel pursuit of regasification
and liquefaction projects.
A group of government agencies is expected to present
a feasibility study of LNG imports this week, which may
drive the process forward. The Colombian government
and local power industry want to begin importing the fuel
by December 2014.
It appears to be too early for a liquefaction plant, while
Colombia’s largest private producer, Canada-based Pacific
Rubiales, is stalling over plans to build a small floating
LNG (FLNG) to export gas to the Caribbean market by
mid-2014.
“Given Colombia’s current alternative between LNG
imports or exports, the first scenario is going to prevail,”
Verónica Vázquez, an associate director at the Cambridge
Energy Research Associates (CERA) consultancy, told
Interfax last week.
The tightness of Colombia’s gas market makes LNG
imports necessary for power generation flexibility. Most
of the country’s electricity is provided by hydropower.
Colombia produces about 29 million cubic metres
per day (MMcm/d) of gas for commercial consumption.
Its domestic market accounts for 85% of this, with the
remaining 15% exported to Venezuela under a contract
running until 2014. CERA forecasts that Colombia’s gas
export potential will disappear in 2016 in the absence of
major new discoveries.
“[The] Colombian gas supply and demand balance
remains very tight. Long-term energy security is the
name of the game for the sector, and diversification is the
appropriate strategy,” said Vázquez.
New gas supplies could come from Colombia’s promis-
ing coal-bed methane resources, or from Venezuelan
pipeline imports. However, LNG imports should consti-
tute part of the overall gas supply for increased energy
security, according to Vázquez. “I think the government is
putting real effort into this issue,” Vázquez added.
The Colombian Ministry of Mines and Energy,
upstream regulator Agencia Nacional de Hidrocarburos
(ANH), and its gas and power counterpart Comisión
de Regulación de Energía y Gas (CREG) are currently
evaluating the potential cost, size and location of a regasi-
fication plant, a CREG spokesman confirmed to Interfax
last week. A report on their findings is expected to be
presented soon, he added.
The regasification terminal is likely to be a floating
facility with an import capacity of 7-10 MMcm/d, ac-
cording to a separate pre-feasibility study of LNG imports
commissioned by CREG in 2011. The terminal is likely
to rely on spot cargoes to meet peak demand rather
than being locked into long-term supply agreements,
the study concluded.
LNG import plans are supported by local utilities
keen to secure back-up for their hydropower plants. This
has become more urgent in recent years because of the
increasing volatility of the El Niño warm weather pat-
tern, which has exposed the vulnerability of Colombia’s
hydropower-dependent generation mix.
The share of gas in power generation jumped
from 15% to 34% during the 2009-2010 El Niño season,
which forced distributors to ration supplies to industrial
consumers.
Juan Guillermo Londoño, the president of Colombia’s
fourth-largest power generator, Colinversiones, told the
BNamericas news agency in December 2011 that Colom-
bia needed to import LNG by 2014-2015 to avoid a more
serious supply crunch.
Colinversiones is part of a group of power companies
that are considering sites for a potential regasification
terminal. Shortlisted locations include Cartagena on the
Caribbean coast, and Buenaventura on the Pacific coast.
Just south of Cartagena in the Lower Magdalena Basin,
Pacific Rubiales is working on an export project from its
La Creciente field via small-scale FLNG. The Colombian
government allowed private companies to export LNG
as long as the country maintained enough gas reserves
for at least eight years. However, Pacific Rubiales and its
marketing partner, Belgian company Exmar, are yet to
secure any supply agreements for their export venture.
The plant’s launch has been delayed from 2012 to 2014
as a result.
“We believe LNG import projects are more critical and
strategic for Colombia than such export schemes,” said
Vázquez. “The development of LNG imports is a strategic,
rather than purely market decision. Even if Colombia
eventually unlocks its unconventional resources, diver-
sification of supply will remain a policy priority for the
country,” she added.
Contact editorial at editorial.news@interfax.co.uk
LNG imports are Colombia’s priority
Despite its pursuit of LNG liquefaction projects, Colombia will need to import LNG by 2014-2015 to avoid a serious shortfall.
A government report due this week should drive the process forward, reports Anatoly Kurmanaev
Colombia’s LNG conundrum
bcm
Source: BP Statistical Review of World Energy 2011Production Consumption
0
2
4
6
8
10
12
20102009200820072006200520042003200220012000
Despite gas production
outstripping consumption,
Colombia will need to import
LNG to meet demand

10. Americas
Producers feel heat in Argentina as subsidies fail again
The Argentine government has
asked oil and gas companies to
operate fields at full output.
The decision is likely to put
further pressure on the hydro-
carbon industry, which also saw
its $461 million tax break wiped
out last week as Buenos Aires
implemented a host of austerity
measures. However, the ‘Gas Plus’
subsidy in the country looks safe
for now, despite its reported inef-
fectiveness in terms of increasing
production.
Planning Minister Julio de Vido
urged companies to maximise field
output on Friday, just one day after
cancelling the ‘Petróleo Plus’ and
‘Refino Plus’ tax benefits for large
hydrocarbon companies. “The
suspension of these programmes
is a symptom of changing local
market conditions and current oil
prices, which makes it unnecessary
to give any benefits to ‘Big Oil’,” de
Vido was quoted as saying by state-
owned Telam news agency.
Both of these programmes,
which were adopted in 2008, were
initially suspended at the beginning
of 2012. The oil and gas compa-
nies affected by the suspension
of ‘Petroleo Plus’ include BP-
subsidiary Pan American Energy
(PAE), Repsol-owned YPF, China’s
Sinopec, Pluspetrol, Total Austral,
Enap Sipetrol and Brazilian state-
controlled Petrobras. At the time of
publication, none of the companies
was available for comment.
The Argentine government is
unhappy with the pace of explo-
ration and production, and the inef-
fectiveness of oil and gas subsidies.
“Companies took advantage of the
[Petróleo Plus] benefits and added
reserves, such as Apache, Medanito,
Roch and several smaller compa-
nies, but unfortunately could not
reverse the overall decline [in pro-
duction]. This is because the largest
oil company in our country, YPF,
has not invested in exploration, nor
has it managed to commercialise oil
shale deposits,” de Vido added.
De Vido said that YPF’s produc-
tion decline wiped out the benefits
of the country’s Gas Plus incen-
tives, an Argentinian government
programme allowing conventional
and tight gas wellhead output to
be priced at above the national
average. He said Gas Plus allowed
producers to add 10 million cubic
metres per day of production in
2011, but that YPF’s production
slipped by 9% last year, which
required increased LNG imports.
Apache, Total and other produc-
ers have already signed deals in Ar-
gentina for selling Gas Plus output
at between $4 and $5 per million
Btu (MMBtu). The national average
price for gas output is now running
at $2.60/MMBtu. However, analysts
are concerned about the sustain-
ability of the subsidy environment,
as well as the lack of a regulatory
framework governing the country’s
huge shale gas resources. The main
problem is finding an economic
equilibrium that incentivises the
country’s producers, while protect-
ing squeezed consumers.
“Like oil, we need to extract im-
mediate value from unconventional
gas to put it at the disposal of Ar-
gentine industry and consumers,”
said de Vido. “We should therefore
make all necessary efforts to in-
crease production in the framework
of existing rules,” he added.
Political pressure on large oil
and gas companies, rather than a
removal of their subsidies, appears
more likely. Only last week, a
consortium of companies led by
PAE was granted a new conces-
sion to produce gas in Argentina’s
Salta Province. Other companies
authorised to participate in the
project include Apco Oil and Gas
International, WPX Energy unit
Northwest Argentina Corporation,
YPF and Royal Dutch Shell unit
O&G Developments.
Gas reserves in Argentina fell by
half between 2000 and 2009, and
production from mature fields has
been declining since 2004. This
has forced Buenos Aires to import
record cargoes of LNG to satisfy de-
mand. Argentina may soon launch
its third tender in three months
to secure the cargoes it needs. The
government is seeking ways of pass-
ing on these costs to consumers.
State energy firm Enarsa has said
it wants to import up to 80 cargoes
this year, which is 21% more than
in 2011, but both internal and ex-
ternal disagreements over price are
thought to be hindering the pro-
cess. Enarsa has turned down bids
from suppliers after they exceeded
its ceiling of around $16/MMBtu.
The news is a sign that the
government is leaning towards a
long-term import regime to cover
demand, rather than attempting
to relax regulation to encourage
exploration and production.
“[President Cristina] Kirchner’s
administration appears commit-
ted to continued LNG imports
rather than providing incentives for
producers. History supports this
theory; the government capped
prices back in 2002, and with every
new government, there’s a discus-
sion about whether these will be
lifted, but it hasn’t happened yet,”
Fitch analyst Ana Ares told Interfax
last month.
“Now we have this government
for another four years, and there’s
been no discernible change to [up-
stream] energy policy. Caps have
been removed in some regions,
but it’s too early to tell if this will
be enough, or if there will be a
Chris Noon
policy & regulation | argentina
Monday 6 February
• EMEA Unconventional Gas
E&P Forum, Istanbul (until 7
February)
• E&P Information & Data
Management conference,
London (until 7 February)
Tuesday 7 February
• BP Q4 earnings release
• E-world conference, Essen
(Until 9 February)
Wednesday 8 February
• TNK-BP event about oil and
gas projects in the Yamal-
Nenets Autonomous District
and northern Krasnoyarsk
• BHP Billiton interim results
for half year 2011-2012
• Statoil Q4 earnings release
• Oil and Natural Gas Corp. Q3
2011-2012 results
Thursday 9 February
• Maria das Graças Silva Foster
to be indicated as Petrobras’
chief executive at board
meeting
• Royal Dutch Shell 2011 Q4
earnings release
• GDF Suez 2011 Q4 earnings
release
• BG Group Q4 earnings release
• Oil and Natural Gas Corp Q4
earnings release
• 2012 Japan Petroleum Explo-
ration Q3 earnings release
Friday 10 February
• Total Q4 earnings release
• Essar Oil Q3 2011-2012 results
Saturday 11 February
• Columbian hydrocarbon
agency ANH to release more
details on June’s licencing
round
• Kuwait Oil and Gas confer-
ence (until 15 February)
Monday 13 February
• Dubai Electricity and Water
Authority to announce final
shortlist of bidders for the
Hassyan 1 power project
Week Ahead
uniform application of incentives.
“Either way, the Argentine gov-
ernment is cash-constrained, and
its larger LNG requirements this
year are going to make it difficult
for them,” she added.
Contact Chris at chris.noon@interfax.co.uk
Canadian energy regulator the
National Energy Board (NEB)
has approved BC LNG Export’s
application for an LNG export
licence from Kitimat in British
Columbia. The licence permits
BC LNG to export 36 million
tons of LNG over 20 years.
Americas
in brief
Natural Gas Daily
6 February 2012 | 10