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For analysis and commentary on these and other stories, plus the latest oil and gas developments, see inside…
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
NRG
January 2014
Issue 46
News Analysis
Intelligence
Published by
NewsBase
AFROIL 2
Algeria hopes to reverse production
falls 2 ASIAELEC 3
Generating boom in China 3 ASIANOIL 5
OVL enjoys overseas success, but future
looks less clear 5 CHINAOIL 6
Green Dragon emerges from unusual but
beneficial 2013 6 ENERGO 8
Hungary takes the Russian option 8 EUROIL 10
European E&P problems laid bare 10 FSU OGM 11
The rise of the NOCs? 11 GLNG 13
LNG import potential rising in Latin
America 13 LATAMOIL 15
International investors give thumbs-up to
Mexican reforms 15 DOWNSTREAM MEA 16
Kurdish export plans currently little more
than pipe dreams 16 MEOG 18
Iran’s future growth hinges on sanctions
decision 18 NORTHAMOIL 20
Rail accident sharpens focus on crude
transportation 20 REM 22
Phase-shifting the blame in Central
Europe 22 UNCONVENTIONAL OGM 23
China makes shale progress 23
NEWSBASE ROUND-UP GLOBAL
This is the forty-sixth issue of the NewsBase Round-up of Global energy issues.
NRG comes to you entirely at our expense, which we
hope will further increase the value you derive from
subscribing to NewsBase.
NRG covers developments from all global energy
regions and sectors, and brings you the “best of the
best” (as selected by our editors) from each of the
previous month’s weekly Monitors.
The global nature of the energy industry means that
no episode happens in isolation and we hope that
NRG will help to tie up events around the world in
one single issue.
This month, LatAmOil examines the reaction from the
international bond markets to Mexico’s constitutional
energy reform, while MEOG looks at the potential of
the Iranian energy sector to grow if Western-backed
sanctions are lifted.
Please note, it is NOT possible to subscribe to NRG. It is, however, an additional service we provide to our existing subscribers.
NRG NEWSBASE ROUND-UP
–– GLOBAL ––
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NRG January 2014, Issue 46 page 2
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
Algeria is hoping for a turnaround in its
hydrocarbon production, after six years
of declining output and dwindling
interest from foreign firms. During 2013,
despite oil and gas production continuing
to fall, the North African country
exhibited signs of improvement that
should lead to rises in output over the
next five years, according to Sonatrach‟s
chairman, Abdelhamid Zerguine.
In remarks reported on December 27
by Platts, Zerguine told reporters that
Algeria was “showing signs of
recovery”. Speaking on the sidelines of
the company‟s general assembly, he
attributed the recent decline to the award
of some permits to small foreign
operators that did not have the “financial
capacity” to meet the requirements of
local projects, leaving them
“overstretched”. These companies had to
relinquish their licences, Zerguine said,
without naming any specific companies.
Many of the world‟s biggest oil and
gas companies are still active in Algeria,
where Sonatrach dominates the sector,
and is implementing a US$80 billion,
five-year investment programme to
expand its hydrocarbon industry.
However, 2013 was a poor year for the
country, beginning with the deadly
terrorist attack in January on Statoil and
BP‟s In Amenas gas facility, which
ignited latent security concerns about a
market where the threat of terrorist
attacks has long preoccupied overseas
players. Militants from neighbouring
Mali claimed responsibility, with the raid
leaving scores dead, including a number
of foreign workers.
The country‟s crude oil production
stood at 1.14 million bpd in November
2013, down from a peak of 1.37 million
bpd in 2007, according to a recent Platts
survey of OPEC and industry officials.
Meanwhile, as its larger, more mature
fields have depleted, gas production had
also declined. Data from BP showed that
output came in at 81.5 billion cubic
metres in 2012, down 1.7% on the
previous year and marking a steady
decline since 2005.
Local faults
To some extent, Algiers has itself to
blame. It sits on oil reserves of 12.2
billion barrels, the third largest in Africa,
and natural gas reserves of 4.5 trillion
cubic metres, the second largest on the
continent. Even before the attack at In
Amenas, though, international firms
viewed Algerian production terms as
unattractive at a time of rising global
competition. This was mirrored in
embarrassing auctions for oil and gas
exploration licences from 2008 to 2011,
with few foreign investors signing up
acreage.
Unsurprisingly, the Sonatrach
explanation made no reference to local
accountability – and in particular to
Algeria‟s internal struggles with
corruption – or its protracted legislative
processes, a growing resort to resource
nationalism as oil prices have soared and
the increasing pain inflicted on its
overseas production partners.
Algeria‟s hydrocarbon production
began to slow in the wake of new
revenue-sharing laws and taxes
introduced in 2005, and a 2006 clause
that imposed heavy tariffs when oil
climbed over US$30 per barrel. In 2009
alone, production slumped by 5%,
against a backdrop where there was talk
of retroactive renegotiations of contracts.
Confidence in the country‟s energy
environment was undermined by a series
of management shake-ups at Sonatrach,
including one related to a corruption
investigation in 2010, followed by the
replacement 18 months later of the firm‟s
head. As a result, some foreign firms
threatened to quit the country for good.
By mid-2012, though, Algiers was
starting to show it might be ready to
address these concerns, via a pledge to
overhaul its hydrocarbon laws in a way
that would prove more appealing to
foreign explorers. However, when the
new legislation was finally gazetted, in
October 2012, the focus was on potential
shale projects, frustrating existing
partners engaged in conventional
exploration and production.
Last year brought little improvement,
as output continued to decline, and the
violent raid at In Amenas forced global
companies to rethink their stances on oil
and gas fields in the Maghreb region –
and in many cases to consider higher
levels of protection, as perceptions of
regional risk head northwards. Algeria
was also beset by a new corruption
scandal, this time involving alleged
payments involving Eni‟s subsidiary,
Saipem.
AfrOil
Algeria hopes to reverse
production falls
Last year got off to a bad start for Algeria and its energy industry. The government is
hoping this year will stem its declining production
By Kevin Godier
Algeria’s oil production fell to 1.14 million bpd in November
The country’s regulations are considered to be among the most onerous in the world
Results from the delayed bid round will be closely watched
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NRG January 2014, Issue 46 page 3
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
As the year wound down, one item of
good news came from an announcement
that Norway‟s Statoil had decided not to
sell its local assets, and would begin
returning its staff to local Algerian sites
as the fear of new terrorist attacks
tapered off. The government and the
military have maintained their focus on
combating the Islamist threat from Libya,
Mali and other regional trouble spots.
High hopes
Illustrating the more positive outlook for
the sector, Algerian Minister of Energy
and Mines Youcef Yousfi said on
October 1 that he expected oil and
natural gas output to double in seven to
10 years, as the country brings fields in
under-explored regions on stream.
Yousfi told reporters in London that
the Maghreb state was continuing to
make oil and gas finds in the eastern
region, where most of its producing
fields are located. New finds have added
at least 1 billion barrels to the reserves of
Hassi Messaoud, Algeria‟s oldest field
that supplies about one third of its oil
production, he said.
The minister went on to add that the
government planned to step up
exploration in the southwestern region,
start offshore drilling and develop shale
and tight gas reserves. “We have between
300 and 500 technically recoverable
trillion cubic feet [8.5-14.16 tcm] of gas
in tight gas,” he said while attending the
Oil & Money conference. “We are
progressing in the evaluation of shale gas
in the country and it‟s above 700 tcf
[19.82 tcm].”
Importantly, Algeria is keeping export
volumes unchanged by finding new
customers to offset a drop in European
fuel consumption that has affected sales
to the countries such as Spain, where the
economy has tanked. “We have accepted
to reduce our exports to these countries
for a small period of time but generally
we didn‟t reduce our production,” Yousfi
said. “We are exporting some quantities
to new markets.”
On the political front, stability seems
assured. Algerian President Abdelaziz
Bouteflika is seen by observers as very
likely to be re-elected in April, despite
being afflicted by the stroke he suffered
in April 2013. Constitutional changes
allowing him to be elected for a fourth
term must be put in place by February or
March, opening the way for a regime
where other senior cabinet members will
assume key administrative and political
roles.
Less attractive to the global oil and gas
community has been the delay in
implementing Algeria‟s planned fourth
licensing round. A number of dates had
been given for this in 2013, but none
came to pass.
Reversing the ongoing decline in
output by the end of 2018 is undoubtedly
a feasible target, given Algeria‟s strong
energy sector potential and options. But
political and energy sector leaders will
have to demonstrate a more flexible and
entrepreneurial attitude, given persistent
concerns that the incentives attached to
the promised round may still be
insufficient to attract foreign majors.
China‟s big five state-owned power
companies are enjoying their biggest
profits bonanza for 11 years as low
domestic coal prices help to reduce their
operating costs dramatically.
Coal fuels the bulk of the 584,000 MW
of capacity operated by the big five, and
fuel represents about 70% of a thermal
power plant‟s (TPP) operating costs,
according to the Shanghai financial
services company ChinaScope Financial.
“While coal enterprises are suffering
heavy losses, China‟s power generation
sector, especially the five major power
generation corporations, has just started
to make a fortune out of the sharp falling
coal prices,” said ChinaScope.
The big five are: China Huaneng
Group; China Datang, China Huadian,
China Guodian and China Power
Investment.
AfrOil
AsiaElec
Generating boom in China
Low coal prices since 2012 have allowed China‟s big five generators to post their largest
profits for 11 years. Cheap coal means consumption is set to rise further, despite Beijing‟s
concerns about pollution
By Graham Lees
Huadian Power is forecasting the largest profits for 2013, set to be 195% higher than in 2012
Yet the coal industry profits fell by 39% in 2013, leaving loss-making companies US$6.71 billion in the red
Low coal prices have not hindered rising imports or investment in new coal projects
The power sector is still set to be a major consumer of coal as generation move away from the cities
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NRG January 2014, Issue 46 page 4
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
Profits
The biggest individual company profit in
2013 was achieved by Huaneng, with
US$3.44 billion, said the China Daily
newspaper.
It is a swings and roundabouts
business, though. Domestic coal prices
have been falling since the middle of
2012, but prior to then the five giants
suffered severe losses owing to high coal
prices, noted ChinaScope.
In the five years up to the end of 2012,
the corporations now enjoying record
profits clocked combined losses of more
than 100 billion yuan (US$16.54 billion),
said ChinaScope.
Huadian Power has signalled that it
expects its 2013 net profit could be as
much as 195% higher than for 2012,
when its profit was logged at 1.42 billion
yuan (US$234.7 million). The firm said
its electricity production in 2013 was
almost 12% more than in 2012, at 175
billion kWh.
Meanwhile, overall profit levels in
China‟s coal industry fell by almost 39%
in 2013, and the “unprofitable producers”
suffered a combined 40.6 billion yuan
(US$6.71 billion) loss, according to the
China Coal Industry Association (CCIA)
last week.
National coal production climbed by
50 million tonnes to 3.7 billion tonnes in
2013, but consumption grew only 2.6%
to 3.61 billion tonnes, said the CCIA.
This was a major slowdown – over the
preceding 10 years up to 2012, the
average annual production increase was
200 million tonnes, said the industry
agency. “Excess supply is expected to
last this year,” it said.
Imports and investment
It is sometimes hard to comprehend
national policy on coal, which seems to
suffer a kind of schizophrenic existence:
loved on the one hand for its abundant
energy value, reviled on the other for its
devastating pollution and huge effects on
the national health.
As energy research scientist Chi-Jen
Yang, of the Center on Global Change in
the US, told NewsBase earlier this
month, “I don‟t think the contradiction is
intentional. China‟s national and local
policymakers simply have not worked
out a consistent plan for coal use.”
Curiously, the slump in China‟s
domestic coal prices has not curbed coal
imports nor deterred the bigger state coal
miners from planning to invest heavily in
more production.
Imports grew by more than 13% in
2013 over 2012 figures to 327.1 million
tonnes, said the CCIA. Much of this was
low-calorific value cheap coal from
Indonesia – which the central
government had pledged to curb as part
of efforts to reduce urban air pollution.
Even so, China Coal Energy, the
country‟s second biggest miner, has just
announced details of a US$2.8 billion
investment in a large new mine in
northern Shaanxi Province.
Hong Kong-listed China Coal is
targeting an eventual annual production
from the mine of 15 million tonnes,
although it will take five years to develop
fully.
Funding for the new mine will come
from bank loans and the coal produced
will fuel gasification and power projects,
said Bloomberg Finance.
Policy and reforms
China‟s coal industry is clearly not about
to collapse owing to the sliding prices
which are helping the power firms to
profit. The central government is
enacting new rules to help miners survive
and prosper.
State aid plans on tax reforms designed
to ease the financial pressure on coal
miners are imminent, according to the
China Resources Journal.
These reforms include a scheme
whereby coal tax collection will be based
on sales value rather than the existing
system linked to production volume, said
the Beijing Global Times. The maximum
resource tax is expected to be reduced to
5% from 8% at present, it said.
Coal stocks at major mining
enterprises are high, while inventories at
the big power groups are being
deliberately kept low in order to benefit
from sliding prices, the CCIA.
About 300 million tonnes of coal
production, mostly from ageing mines,
was taken out of the supply market in
2012, but 300 million tonnes of new
production is due to come into operation
during 2014, said John Foley, China
editor of Breakingviews, a financial
analysis service of Reuters.
This is in addition to the 100 million
tonnes of new capacity given the go-
ahead for development in 2013.
“If the authorities are serious about
cleaning [urban air pollution in] China,
deeper reforms are needed. Local
governments have little incentive to
enforce [the] closure of inefficient mines
only to see smarter new facilities built in
someone else‟s town,” said Foley in a
January 14 analysis. “Curbs in imports of
the dirtiest varieties may just serve to
keep low-quality domestic producers
alive.”
As NewsBase has noted before, the
central government‟s promise to tackle
coal pollution which suffocates dozens of
big cities does not mean reducing the
volume of coal burnt for energy; it
appears to mean relocating coal burning
away from the urban areas.
Huge new mines are planned in
sparsely populated northern and
northwestern areas, and the coal from
these will fuel new mine-head power
plants or massive coal-to-gas projects
which will in turn feed into power plants.
It will be a costly business. The closure
of small, inefficient mines and power
plants in cities will continue, but the rise
of coal energy in China is a long way
from over yet.
AsiaElec
“China’s power generation
sector, especially the five
major power generation
corporations, has just
started to make a fortune
out of the sharp falling
coal prices”
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NRG January 2014, Issue 46 page 5
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
Over the years ONGC Videsh Ltd (OVL)
has been roundly criticised for failing to
snatch up major foreign oil and gas
assets, frequently losing out to quick-
footed Chinese rivals that enjoy greater
financial and political muscle.
Recent events would suggest that all
this might be changing, with OVL
enjoying a streak of successes in Latin
America, Africa, Southeast Asia and
Central Asia. Though the company
appears to be getting to grips with buying
into high value energy targets, however,
its abilities to compete on the world stage
remain at the mercy of New Delhi‟s
domestic energy policy and the resulting
impact this has on parent company Oil
and Natural Gas Corp. (ONGC).
Overseas victory list
In January, OVL acquired an additional
12% stake in Brazil‟s Block BC-10 from
Petrobras by exercising its pre-emption
rights. OVL now owns 27% of the
deepwater Campos Basin Block, while
operator Royal Dutch Shell holds
balance.
Significantly, the Indian firm managed
to outmanoeuvre Sinochem, preventing
the Chinese state firm from investing in
the block. OVL agreed to pay US$529
million, matching Sinochem‟s offer. The
block produces about 50,000 barrels per
day of oil and, according to ONGC, has
the potential to reach 75,000 bpd by
2017.
The Brazilian success follows OVL
and Oil India Ltd‟s (OIL) completion of
their acquisition of Videocon‟s 10%
stake in Mozambique‟s giant Rovuma
Area-1 gas field for US$2.4 billion this
month. OVL has also bought a 10% stake
in the block for US$2.6 billion from the
US‟ Anadarko Petroleum, with the
Indian explorer set to complete the deal
before the end of February.
“Area-1 has [the] potential to become
one of the world‟s largest LNG
producing hubs and is strategically
located to supply LNG to growing Indian
gas market,” OVL said in a statement last
week.
OVL‟s other successes include
winning two onshore oil blocks in
Myanmar in October 2012, adding to
existing stakes in the A-1 and A-3 gas
blocks and three other offshore acreages
in the Southeast Asian country. In 2013,
meanwhile, OVL acquired a 2.7% stake
in Azerbaijan‟s Azeri, Chirag and
Guneshli fields for US$1 billion.
In December 2013, OVL bid for three
blocks in Sri Lanka in the Mannar Basin
where Cairn India has made two gas
discoveries.
In Venezuela, meanwhile, OVL signed
a memorandum of understanding (MoU)
with Venezuela‟s PDVSA in October
2013 for co-operation in the oil-rich Faja
area. “Venezuela has world‟s highest
reserves and we have a huge market,”
OVL said.
OVL, buoyed by its successes, appears
ready to take on more foreign ventures
and acquisitions in the near future.
Future moves
The company, along with partners, is
looking to buy a 9-10% stake in Russian
gas producer Novatek‟s US$20 billion
Yamal LNG project.
Sudan offered OVL two oil and gas
blocks this week, with the company set
to take 100% stakes in the licences if it
finds them feasible.
Vietnam has offered the company five
offshore exploration areas in South China
Sea as well as the Kossor Block in
Uzbekistan without having to bid.
OVL is also set to discuss a possible
partnership with Ecuador‟s state-run
Petroamazonas later this month.
Moreover, the company is also looking
into investing in Kazakhstan‟s “Eurasia
Project”, which will see the development
of oil and gas assets in the northern
Caspian Sea. The sea boasts 300 oil and
gas fields, including super-giants such as
Karachaganak, Tengiz and Kashagan.
ONGC officials have said the company
has set aside misgivings over Astana‟s
decision last year to block OVL‟s US$5
billion bid to buy US super-major
ConocoPhillips‟ 8.4% stake in Kashagan
in favour of China.
AsianOil
OVL enjoys overseas success,
but future looks less clear
After years of misfires, OVL has racked up a string of foreign acquisitions. Indian energy
policies, however, may cause financial problems for the major further down the line
By Siddharth Srivastava
OVL completed the acquisition of a 12% stake in Brazil's Block BC-10 in January
Its acquisition of a 10% stake in Mozambique's Rovuma Area-1 gas field should complete in February
ONGC has warned output growth and overseas acquisitions are at risk owing to its fuel subsidy burden
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NRG January 2014, Issue 46 page 6
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
Yet, while OVL has a racked up a
number of notable achievements, its
ability to maintain that momentum lies
with the Indian government‟s domestic
energy policy decisions.
Domestic Policy
ONGC has said it intends to spend 11
trillion rupees (US$178.62 billion) by
2030 to add reserves both at home and
abroad. Indeed, it plans to invest more
than US$9 billion in bringing discoveries
in the prolific eastern offshore KG Basin
into production. Yet at the very same
time, the major has warned that its output
growth and overseas acquisitions are
under “serious threat” owing to the
“disproportionate rise in fuel subsidy
burden”.
“There has been significant reduction
in ONGC‟s net realised prices over the
years, from about US$54.5 to in 2012 to
US$40 presently. Profit after tax from
crude oil has already eroded by almost
50% over last three years,” ONGC has
warned.
India needs to focus on ramping up
domestic exploration efforts, as a result
of net annual oil imports costing the
country around US$100 billion per year
leaving the country on the brink of a
severe energy crisis. The country may be
forced to seek a loan from the IMF,
Indian Oil Secretary Vivek Rae warned
this week, saying: “We haven‟t gone to
the IMF yet, but we are pretty close.”
If the government does not work to
free up ONGC‟s finances then the
company is going to find it increasingly a
challenge to finance development at
home and acquisitions abroad.
This will likely leave the country with
fewer stable supplies of foreign oil in the
long run.
China-focused Green Dragon Gas‟
production soared unexpectedly in 2013,
driven by other companies drilling on its
concessions – it was a most unusual year
for the coal-bed methane (CBM)
developer.
In its January 21 statement, Green
Dragon said total gas output for the year
rose by 304% from a year earlier to 7.19
billion cubic feet (203.62 million cubic
metres). Breaking that down, the firm
said it had produced 2.9 bcf (82.13
mcm), up 11% year on year, while
current audits of “third-party activities”
had delivered the remaining 4.29 bcf
(121.49 mcm), with potentially more to
come.
The extra production came from some
of the 1,500 wells drilled by a handful of
the country‟s biggest state-owned majors
on its licences, of which Green Dragon
said it had no knowledge. At the heart of
how this strange state of affairs came to
be is state-owned China United Coalbed
Methane‟s (CUCBM) claim in 2011 that
Green Dragon‟s licences had been
revoked, the central government
enforcing the independent‟s rights in
2013 and the subsequent revelation that
third parties had carried out extensive
drilling work in the intervening period.
From there…
In March 2011, CUCBM announced via
its website that it had ended its co-
operation with Green Dragon in four of
the five production-sharing contracts
(PSCs) it has with the independent and
would not be extending those contracts.
These were the Qinyuan and Shizhuang
North (GSN) Blocks in Shanxi Province,
the Fengcheng Block in Jiangxi and the
Panxie East Block in Anhui. Shizhuang
South (GSS) was left untouched, while
Green Dragon‟s PSC for the Baotian-
Qingshan Block is held with PetroChina.
Despite the announcement Green
Dragon affirmed its claim to the PSCs,
saying that all financial commitments
had been met and that the contracts were
in full force and effect. Such a move was
highly unusual for a privately owned
foreign company to make in China, given
the power of the country‟s state-owned
enterprises (SOEs). Nevertheless, the
company continued to operate the
licences, while CUCBM refused to
answer NewsBase’s requests for
clarification on the matter.
AsianOil
ChinaOil
Green Dragon emerges from
unusual but beneficial 2013
The past year has proved eventful for the CBM developer, with the discovery of more than
1,500 wells drilled across its licences
By Andrew Kemp
Green Dragon's production soared by 304% year on year in 2013, driven by third-party drilling
Around 1,300 wells were located on the producing Shizhuang South Block (GSS)
The company estimates its 1P reserves have jumped more than sevenfold as a result of the drilling
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NRG January 2014, Issue 46 page 7
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
In July 2013, however, Green Dragon
announced that the Chinese Ministry of
Land and Resources (MLR) had
reaffirmed the validity of its licences.
What Green Dragon describes as
CUCBM‟s “erroneous” statement was
removed from the company‟s website
just days prior to the independent‟s
announcement.
On October 8, Green Dragon revealed
that CUCBM, China National Offshore
Oil Corp. (CNOOC), China National
Gasolineeum Corp. (CNPC) and
PetroChina had informed it of 1,500
wells that had been drilled across five of
its PSCs. Around 1,300 of those were
located on the company‟s sole producing
block, Shizhuang South (GSS), and had
been drilled at an estimated cost of
US$500 million.
The company has since revealed the
signing of a memorandum of
understanding (MoU) with PetroChina to
confirm the state-owned company‟s
“participating interests” in the
Chengzhuang Block (GCZ), which is
part of GSS, as well as a heads of
agreement (HoA) with CNOOC on a
“potential transaction” relating to the
drilling work.
In an interview with NewsBase, Green
Dragon‟s chairman and founder,
Randeep Grewal, described the situation
as “globally unprecedented”, stressing
the protections that should have stopped
such a situation from arising in the first
place. He pointed to the company‟s PSCs
as being “directly authorised, certified,
accepted and approved by the State
Council” and the fact that they were
protected by a bilateral investment treaty
between the Netherlands and China.
Green Dragon signed the PSCs via a
Dutch-listed subsidiary.
… to here …
Grewal explained that it had taken two
years for the company to secure its PSC
rights because it had adopted a
“conciliatory approach” in lobbying the
State Council, the Ministry of Commerce
(MOFCOM) and the MLR, rather than
pursuing legal recourse.
With Green Dragon‟s claim to the
licences having received Beijing‟s
support, the four state-owned companies
submitted information on their drilling
activities.
Grewal explained that while the
company had seen signs of some third-
party drilling following CUCBM‟s move
to revoke the contracts, he insisted that
the company had no idea of the scale,
which he described as “overwhelming”.
Green Dragon, he said, had encountered
external drilling activity around 10-15
times prior the concessions‟
reinstatement, with the company
“notifying” CUCBM of each encounter.
“At no time, until recently, did we
have any idea that there was a campaign
to the tune of 1,500-odd wells. That‟s a
whole different level,” he said. “It‟s so
unprecedented that it‟s difficult to
comprehend that something like this
could happen, let alone be vigilant to
such activity.”
While the heavy focus on GSS is of
little surprise, given that it is the only
concession in production, what is
startling is that drilling activity even took
place, given that CUCBM never issued a
statement ending Green Dragon‟s
involvement there. When asked about
this, Grewal simply responded by saying:
“GSS was never threatened because of
the existence of the [overall development
plan] ODP.”
However, Grewal said that, after
having conducted field studies, it was
clear from the amount of infrastructure in
place at GSS that the block was “well
over 50% developed”.
… and beyond
Green Dragon‟s plan for its six licences
has been based on first developing GSS,
before expanding its operational scope.
With GSS‟ development so much further
along than originally expected, the
company‟s development plans have been
accelerated.
With 150 LiFaBriC wells, which use
technology adapted from traditional
horizontal drilling techniques, slated to
be drilled in GSS this year, Grewal does
not expect to there to be much
development work left before the block
is fully completed. When pressed on the
exact relationship with its newfound state
partners, whether there would be a farm-
in agreement and if co-development was
on the cards, Grewal declined to
comment.
However, Grewal said: “By the time
we hit the end of 2015 we should pretty
much be done with GSS and the logical
thing would be to continue that drilling
campaign into GSN.”
He added that there was only a lease
boundary between GSS and GSN, with
the former enjoying extensive
infrastructure development.
ChinaOil
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NRG January 2014, Issue 46 page 8
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
While the past six months have
brought about significantly better news
for the company, spurring a 40% rally in
its share price in the same period, there is
still some way to go before it recaptures
the value lost in the wake of CUCBM‟s
original statement.
Market watch
The uncertainty surrounding Green
Dragon‟s position has seen the London-
listed company‟s value drop from around
US$1.6 billion in March 2011 to slightly
more than US$600 million at present.
Commenting on the valuation, Grewal
said Green Dragon had enjoyed a “very
productive period of time” despite the
uncertainty caused by the CUCBM
notices.
He said: “Our wells have continued to
perform remarkably well, our production
levels are up, our infrastructure has built
up. In every regard operationally we‟ve
done well.”
He added: “What are my expectations
[of the market]? At a minimum we need
to go back to the point before these
erroneous notices were put out. From
there all the accretive activity we have
accomplished should be compounded on
top.”
He pointed to the fact that prior to
CUCBM‟s statement Green Dragon‟s 1P
gas reserves stood at 40 bcf (1.13 bcm)
and 2P reserves stood at 270 bcf (7.65
bcm). Following the retroactive
application of the licences by the MLR,
Green Dragon‟s engineers‟ estimates
based on information provided by the
third parties put 1P reserves at 300 bcf
(8.5 bcm) and 2P reserves at 600 bcf
(16.99 bcm).
The company expects to have
completed an audit on its assets in the
next few months, with Grewal adding
that the “abundance” of data delivered
may delay the announcement of its
reserve data until the end of the first
quarter, rather than in February.
Lessons
Last year, therefore, was an unusual year
– but not unsatisfactory – with Green
Dragon closing out 2013 in a better
position than it entered.
Still it remains to be seen whether
investors rally behind the company,
returning its lost market value.
China is certainly hungry for gas, and
having its licences confirmed by the
central government will be a mark in its
favour.
Yet, understandably, cautious
onlookers will want to see how the
company handles its development
partners in the future.
Even as the company seems to be
emerging from a somewhat turbulent
time, taken from a fairly lengthy period
in the country, it raises serious questions
about foreign independents and their
participation in China‟s CBM sector.
Could this to happen to other CBM
developers that do not have similar
guarantees to fall back upon? While it is
difficult to say with any degree of
certainty, in Green Dragon‟s case Grewal
highlighted the company‟s “first
generation” of licences that had been
maintained in their original form as
having afforded it a much stronger
position from which to protect its
interests.
Speculating on what may have
prompted such a unilateral approach to
Green Dragon‟s licences by the state-
owned giants, Grewal said: “There is a
tremendous amount of pressure on all
domestic producers, including us, to get
domestic gas production up and we‟re all
incentivised to achieve that. [However],
we still have to do it within the confines
of the rules, regulations, PSCs and rigid
obligations in place.”
Hungary‟s US$10 billion loan deal with
Russia to expand the Paks nuclear power
plant (NPP) has come under intense
scrutiny at home as Hungarians wait to
hear the full terms.
The deal was signed last week and was
described by Hungarian Prime Minister
Viktor Orban as an “excellent
professional agreement.” However, the
agreement was struck without any
involvement from the Hungarian
Parliament, while it could also come
under fire from Brussels.
“The information provided about the
deal is way too insufficient,” Judit Barta,
managing director of Hungary‟s GKI
Energy Research Institute, told
NewsBase.
ChinaOil
Energo
Hungary takes the Russian option
Hungary‟s deal with Russia to expand the Paks NPP is causing considerable controversy,
with critics saying the electricity produced will be too expensive for consumers
By Robert Smyth
Russia is to lend US$13.55 billion over 30 years to fund the 2,400-MW expansion of the Paks NPP
Critics say the deal could be seen by Brussels as illegal state aid
The terms of the deal could make the price of power from Paks far too high
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NRG January 2014, Issue 46 page 9
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
“The government had no right to make
such an agreement, as Parliament had
only given a mandate for the government
to look into the possibilities,” she noted.
The loan
Russia has pledged to lend Hungary as
much as 10 billion euros (US$13.55
billion) as a 30-year sovereign loan to
expand the Paks NPP by building two
new reactors that will add 2,400 MW of
new capacity.
This sum should cover around 80% of
the costs of the work, the ceiling of
which is estimated at 12 billion euros
(US$16.25 billion).
Russian nuclear agency Rosatom is set
to build the new blocks, which will more
than double the NPP‟s existing capacity.
The agreement was signed by Russian
President Vladimir Putin and Orban in
Moscow on January 14. Since then,
Orban has said that Hungary cannot be
competitive without it.
Political controversy
Orban has come under criticism at home
for increasing Hungary‟s energy
dependence on Russia, as well as for
rushing into a deal for the plant‟s non-
urgent expansion.
The opposition E-PM electoral alliance
leader and former Prime Minister Gordon
Bajnai has called for a demonstration
against the expansion on February 2,
with the goal of forcing a referendum on
the issue.
Parliament reconvenes on February 3
ahead of a general election on April 6.
The ruling Fidesz party has hit back at
Bajnai‟s comments, saying that when he
was in power before 2010 he was in
favour of expanding the Paks NPP.
Despite the controversy, the Russian
deal represents a quick and decisive
piece of business when compared to the
long drawn-out expansion of the Czech
Republic‟s Temelin NPP.
The first new block could start
operating in 2023, Hungarian State
Secretary Janos Lazar told the press. He
also mentioned that the European Union
had already given its backing to a draft
plan for the building of the new units.
Pricing problems
However, GKI Energy‟s Barta
questioned whether the deal had really
been approved by the EU and said that
there was no pressing need to decide on
the expansion for at least the next five
years.
She also claimed that Lazar‟s
statement that the Hungarian government
would be responsible for paying back the
loan, while the Paks NPP effectively
received the investment cash as a grant,
could represent a case of illegal state aid.
“Brussels will surely launch an inquiry
into illegal state aid should electricity
prices not include interest on the loan
taken. There may also be a probe if the
Paks NPP receives a capital injection or
other state money to help repay loans
already taken for capacity expansion,”
Attila Vago, a senior analyst at Concorde
Securities in Budapest, told NewsBase.
While Vago said there was no question
that Hungary needs cheap energy, as the
country‟s gas and oil imports are high, he
expressed concerns about the potential
terms of the deal.
“The interest on the loan will be huge,
and therefore the sale price of electricity
produced by the new blocks would be too
high,” he said.
Assuming an annual return of 8% on
the equity, which is around 20% of the
estimated investment cost, the eventual
price of the electricity would
theoretically be around 95 euros
(US$128.68) per MWh, more than
double the current wholesale price in
Hungary.
“Someone will cover the difference
and that will probably be the tax payer,”
he said. The 10 billion euro loan will
increase state debt by 10% in terms of
GDP and the interest burden may
represent 0.4% of GDP in the years after
the new nuclear capacity comes on line,
most probably in 2023-24, he added.
“Everything depends on financial
terms. What really concerns me is that all
parties are fully convinced of the
economics and the necessity of this
project, but nobody knows exactly about
the real cost, construction time and future
energy prices,” said Vago.
Hungarian Economy Minister Mihaly
Varga told local TV news channel HirTV
on January 15 that the government was
negotiating to secure the cheapest deal
for Hungary.
Not all analysts have questioned the
agreement. Takarekbank analyst Gergely
Suppan told Hungarian news agency
MTI that the expansion would drive
investment and with it Hungary‟s GDP
growth.
He also welcomed the stable financial
background that the loan provides,
adding that if the interest rate was below
market rates, then a good return on
investment could be realised.
No tender
The agreement also means the tendering
process that was expected to involve five
international players will not see the light
of day.
There is already a Russian connection
at Paks, as its existing four VVER-440
reactors – with 2,000 MW of combined
capacity – were built in the USSR.
They were installed between 1982 and
1987 and fuel is currently provided by
Rosatom subsidiary TVEL.
Vago observed that Hungary, a
member of the EU since 2004, is the first
EU member country to accept Russian
nuclear technology on such a large scale.
“No doubt this is a huge victory for
Russia as well as Putin,” said Concorde‟s
Vago.
However, nuclear energy is not natural
gas, in that Russia cannot utilise it as a
geopolitical weapon, as it often does with
gas.
Therefore Hungary is not necessarily
increasing its energy dependence on
Russia.
Energo
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NRG January 2014, Issue 46 page 10
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
However, Hungary does remain overly
dependent on expensive Russian gas,
even if natural gas imports from Russian
have dropped by as much as 35% since
2008 because of lower consumption and
the growing availability of cheaper gas
from the west.
“If Hungary sufficiently diversified its
gas supply towards the west, it could
achieve lower electricity prices as well,
ceteris paribus [all other things being
equal],” said Vago.
The Paks NPP contributed 43% to
Hungary‟s electricity supply in 2011.
Last October, Orban told a Hungarian-
Indian business forum in Mumbai that
Hungary was planning to raise nuclear
output by 50-75% by 2023.
The deal with Russia seems to be a
technically and financially expedient way
to achieve this for the government, but
Budapest will have to contend with
further political fall-out and reassure
consumers that price will not rise.
European oil and gas exploration and
production has been in the doldrums over
the past two years, with a marked lack of
success offshore in both the UK
Continental Shelf (UKCS) and Norway.
This was the dominant theme of the
Outlook for Oil in North West Europe
conference in London last week, which
used the latest exploration and
production data to assess whether
Europe‟s quest for energy independence
is possible or a pipedream.
Speaking to NewsBase on the sidelines
of the conference, David Bamford, one
of the conference organisers, a former BP
executive and now CEO of New Eyes
Exploration, said that rising costs were a
critical issue.
“What is clear is that high costs are
killing the North Sea,” Bamford said.
“This is despite … the UK Treasury
continuing to incentivise oil recovery and
[looking at] the creation of a new
Norwegian-style regulatory authority.
That will not alter the fact that costs are
rising exponentially and as a result,
projects have been either cancelled or
delayed.”
He said several high-profile schemes
had been cancelled, such as the Kristin
Gas Export project and plans to develop
the Rosebank and Bressay fields. Other
projects that have been delayed include
Johan Castberg, Johan Sverdrup, Linnorn
and Tressak. “But in fact, most of the
projects in the Barents Sea are delayed,”
he added.
UK
Despite such setbacks, there are some
shafts of light in the gloom. Delegates
heard that the rate at which North Sea
fields were being brought on stream after
initial discovery had improved
considerably, rising from 15 years in the
1980s to around five years now. But this
is doing little to halt the overall
production decline rate.
Oswald Clint of Bernstein Research
said: “Although the decline rates in the
fields of the UKCS and the Norwegian
Continental Shelf are not as bad as the
Gulf of Mexico, the „real decline rates‟ in
Europe tend to be understated and the
unavoidable truth is that they are
accelerating.”
Clint went on to say: “Last year, we
saw a decline of 13.8% in the UK and
12% in Norway. This was mainly due to
the higher water cut and it is clear that a
decision will have to be taken soon at the
highest levels on EOR [enhanced oil
recovery] to offset this problem.”
For Malcolm Webb, the CEO of Oil &
Gas UK, the problem is a perennial one.
Commenting on Wood Mackenzie‟s
annual review of UK upstream oil and
gas, which followed on the heels of data
released by the Department of Energy
(DECC) on drilling activity in the UKCS,
he said: “We are just not drilling enough
wells in UK offshore waters and those
that we are drilling are not finding
enough oil and gas. This worrying trend
has been growing for some time. It
started in 2011 with a 50% drop in the
number of exploration wells drilled,
[and] has since failed to recover.”
Webb carried on by saying that the
industry in Europe was facing a crisis
that required immediate action. “Our
members tell us that drilling rig
availability and the ability of smaller
companies to secure equity capital are
major hurdles. In any event, it is clear
that we now face a crisis which demands
urgent concerted action … if we are to
maximise economic recovery of our
offshore oil and gas resource and sustain
future production.”
Energo
EurOil
European E&P problems laid bare
The decline of European oil and gas production continues to thwart the continent‟s hopes
of energy independence
By Nnamdi Anyadike
E&P offshore the UK and Norway and in the Netherlands disappointed in 2013
Decline rates in Europe tend to be understated and are accelerating
A lack of exploration risks a collapse in capital spend in a few years’ time, meaning lower future production
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NRG January 2014, Issue 46 page 11
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
The Oil & Gas UK chief said the
situation was a strange one, given the
record amounts of investment in offshore
developments. “The paradox is that the
UK continues to record annual levels of
capital investment at over GBP13 billion
[US$21.6 billion] … Meanwhile,
production from existing fields has fallen
significantly and the total number of
exploration wells has dropped to just 15
in 2013, according to data just published
by DECC.”
For Webb, it is a problem with long-
term exploration planning. “We are
simply not putting enough reserves into
the hopper for future development,” he
said. “Unless we do something about
exploration now, we face a risk of a
collapse in capital spend in a few years‟
time and hence lower future production.”
An OPEC report released last week
backed up the DECC‟s conclusions,
saying the UK‟s oil supply of 860,000
barrels per day in 2013 was at its lowest
level “since1977.”
Norway
In Norway, Bente Nyland, director of the
Norwegian Petroleum Directorate
(NPD), said: “The biggest challenge is
that costs have increased. Higher costs
have already led to some projects being
delayed ... and higher costs and uncertain
future oil and gas prices are a significant
challenge.” The NPD cut its 2014 oil
production forecast to 1.46 million bpd,
in line with last year, but below a
previous 1.52 million bpd forecast. It
also anticipates flat gas production after
earlier predicting a rise. The agency also
lowered its investment forecasts,
predicting just 2% growth over the next
two years before a decline. “If oil and gas
prices fall and costs remain stable or rise,
this will have an impact on decisions to
start up new projects, and will entail
lower investments than included in the
forecasts. To improve efficiency,
mergers and acquisitions activity may
increase. There are a lot of companies on
the shelf,” Nyland said. “We have said
earlier that this kind of restructuring is
possible, particularly now when you see
the capital strains and you need the
capital to fulfil your obligations. That
might be tough for some of the smaller
companies with no production or
income,” she added.
The Netherlands
The Netherlands‟ government has also
revealed that output from the country‟s
giant Groningen field will decline in the
coming three years. Production last year
stood at 54 billion cubic metres, but
output from the field is expected to drop
to 42.5 bcm per year in the next few
years, before falling to 40 bcm per year
in 2016.
Gas from the Groningen field currently
makes the Dutch government around 12
billion euros (US$16.4 billion) per year.
But by 2016 the loss of gas production
from the field will knock 2.3 billion
euros (US$3.1 billion) off that total.
Previously production to 2020 was
projected to average 49 bcm per year.
Henk Kamp, the Dutch Economy
Minister, said the production cut would
be the result of concerns raised by locals
living nearby who are worried about an
increase in earth tremors, which they
allege have been caused by the high rate
of drilling at the site.
Looking at developments in all three
countries, Bamford‟s conclusion was:
“While the US can contemplate a vision
of oil independence, North West Europe
could be destined to remain hooked on
the global geopolitics of oil, increasingly
shovelling money in the direction of
OPEC.”
In a move that might have given Gordon
Gekko a heart attack, Morgan Stanley,
one of Wall Street‟s most revered and
illustrious trading houses, has sold its oil
trading business to Rosneft, a Russian
state-controlled company. The deal was
struck in late December, when the two
sides announced that they had signed a
binding agreement that would allow the
Russian firm to purchase the Global Oil
Merchanting unit of Morgan Stanley‟s
commodities division.
EurOil
FSU OGM
The rise of the NOCs?
In striking a deal on the acquisition of Morgan Stanley‟s oil trading arm, Rosneft is
advancing into new territory. Current market conditions may inspire other state-run energy
operators to follow its lead
By David Flanagan
The agreement is roughly in line with the Russian giant's drive to expand into new markets
It may give the company a boost as it seeks to move into the LNG export trade
Commodity trading may offer NOCs new avenues for profit in the face of tough competition
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NRG January 2014, Issue 46 page 12
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
But now that the initial raised
eyebrows have dropped again, what does
this deal actually tell us about how
Russian energy companies‟ attitudes are
changing? Moreover, what does it say
about how the oil and gas trading
markets are evolving?
Metamorphosis
First of all, the deal concluded a dramatic
and successful year for Rosneft.
The company was once the steady but
unremarkable workhorse of the Russian
oil sector, but in recent years it has
transformed into a trend-setter and a
rapidly evolving global operator. Its
metamorphosis continued in 2013 with
the acquisition of a stake in the Italian
refiner SARAS, the full takeover of the
Russo-British venture TNK-BP and the
completion of its campaign to acquire
100% of the Russian natural gas operator
Itera. Beyond these transactions, it also
stands to benefit from the step-by-step
revamp of the Russian gas market,
including LNG export opportunities.
And now the deal with Morgan Stanley
marks, in quite spectacular fashion, the
elevation of Rosneft into a more mature
and calculating oil trading enterprise.
New direction
Secondly, Rosneft‟s position as a
national oil company (NOC) underscores
the interesting and unusual nature of this
agreement.
It is difficult to think of a precedent for
such an acquisition, given that we are
accustomed to seeing NOCs following a
predictable pattern in their development.
But under present conditions, they appear
to have become more aware of their
power and therefore more aware that
they have different options. This may
explain Rosneft‟s bold step in buying the
Morgan Stanley oil “book.”
The value of the deal has not been
disclosed. However, Rosneft may be less
interested in the “mark-to-market” value
of the trades and more keen on the
prospect of buying a trading structure
and contractual relationships that it can
now use as it chooses.
It is also interesting that fellow
Russian energy firms such as Gazprom
and LUKoil have largely built up the
trading sides of their business through
organic growth, rather than through
acquisitions. By contrast, Rosneft, by
building its market presence through a
high-profile acquisition, has seemingly
tried to play catch-up with rivals in a
short space of time, and it has arguably
now established the foundation needed to
accomplish this feat in one fell swoop.
Changing market conditions
Along with telling us about the changing
nature of Russian energy companies, the
new deal also reflects shifting
fundamental conditions in the oil trading
market. Indeed, rather than being a huge
surprise, the deal between Rosneft and
Morgan Stanley is really a sign of the
times.
That is, oil prices traded in a narrow
range of US$100-110 for most of 2013,
so the prospects for banks and trading
companies have become quite limited.
With such a calm market, banks and
trading houses cannot make much
money. They need price volatility to
make good profits, and that is simply not
happening.
So together with the ongoing need for
rationalisation after the credit crunch and
the increased regulatory burden, market
fundamentals have not favoured banks in
recent years.
Nor have they created the conditions
necessary for banks to make money in oil
trading. This is part of the reason for
Morgan Stanley‟s decision to unload its
oil trading arm. Others are sure to follow
– most notably Deutsche Bank, which is
closing down its commodity trading
operations.
Higher profile
Rosneft‟s new deal is also consistent
with its ambitious recent evolution.
As noted above, the company
succeeded in building up its activities
through the acquisition of oil-producing
and refining assets in 2013. However, its
strength is not confined to the oil sector.
Rosneft also stands to benefit from other
changes. Specifically, Russia moved
quickly in 2013 to relax rules and
regulations relating to LNG exports, an
area of activity that had previously been
the exclusive province of Gazprom.
The new regime is clearly good news
for Rosneft. The company‟s future
involvement in LNG exports is now
virtually assured, given that it has teamed
up with ExxonMobil of the US to draw
up plans for an LNG plant capable of
supplying Asian markets.
Under these circumstances, the higher
profile that the Morgan Stanley deal
gives Rosneft is highly favourable. It
could even facilitate the company‟s
successful entry into the LNG export
trade by encouraging the development of
synergies in cross-commodity trading,
thereby allowing it to develop additional
gas trading expertise.
As such, the agreement between the
two companies illustrates Rosneft‟s
ambitious new attitude to its own future.
But does the deal also mark the start of a
trend among NOCs across the world?
Facing competition
Certain market trends appear to support
this idea.
One of the key problems for NOCs lies
in the serious level of competition
presented by the growth in US shale gas
production. This is not a problem faced
by Russian oil producers alone.
In the Middle East, it has created a
dilemma for OPEC, which must now
determine how it can represent its
members‟ interests in the face of
competitive pressure from US shale gas.
Consequently questions about the future
role of OPEC, which is of course
dominated by NOCs, are surfacing.
Already some tension within OPEC is
evident, and the largest Middle Eastern
producers – including Iran, Iraq and
Saudi Arabia, all of which may end up
pulling in different directions in the
future – have a growing incentive to
strike out on their own. In other words,
these countries may feel that OPEC
membership will increasingly serve as an
obstacle to their freedom to negotiate and
sign contracts.
FSU OGM
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All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
Other trends have also shaken up the
position of NOCs and may spur them
into more self-motivated action. For
example, one trend seen in 2013 – one of
cheap coal stealing market share away
from oil – is sending a signal to NOCs
about the need for action.
In light of these developments, Rosneft
now appears to be leading the market by
example. Middle Eastern NOCs may be
unable to engage in a transaction like the
Morgan Stanley/Rosneft deal for various
reasons, but they will not have failed to
notice it and could be spurred into action
by it. In any event, NOCs cannot rely on
the old-fashioned strategy of simply
increasing oil output, as this will be
inadequate over the longer term. They
must, as Rosneft has now demonstrated,
employ more lateral thinking in order to
ensure that they can make their own
future commercial positions more
lucrative.
Picking up slack
The NOCs now have a big opportunity to
pick up any slack in the oil trading
market left by departing banks and
trading companies.
But while there are many opportunities
for NOCs in the year ahead, they will not
have it all their own way. And indeed,
market conditions will not necessarily
work in their favour.
Many market observers suspect that oil
prices will fall in 2014, as a result of the
potential for increased Iranian crude oil
exports following the relaxation of
sanctions and the continued rise in US
shale gas production. If they are right, the
shift may signal a turn in the so-called
commodity “super-cycle” (if such a thing
exists), whereby rising commodity prices
in the early part of the century are now
being replaced by falling commodity
prices.
If oil is vulnerable to such a price
correction, this is not such good news for
the NOCs, as it obviously erodes their
revenues. But even if oil market
conditions do get tougher for NOCs, this
in itself is also potentially a driver of
change.
Landmark
Last year was a landmark period for
Rosneft. It was the year in which the
company changed its own market
position and in which it altered market
perceptions of its objectives and
ambitions.
With the culmination of the year‟s
work being the acquisition of Morgan
Stanley‟s oil trading business, the group
is now set up for another interesting year
in 2014. We might not see quite so many
headline-grabbing announcements, but
the consolidation work, which will have
the objective of transforming Rosneft
into one of the world‟s foremost NOCs
(and in the longer term, into one of its
most significant energy trading groups)
will now begin.
Perhaps the most interesting element of
this is the question of how Rosneft‟s
changing character may set an example
to other NOCs. That is, on the back of
this deal, it is worth asking whether we
are about to see the rise of the NOCs and
a change in the tide that will be hard to
stop.
Latin America‟s potential to serve as a
key destination market is being closely
examined by the embryonic US LNG
industry, which is continuing to shape up
for a long-term role as one of the world‟s
largest gas exporters. The opportunity
certainly exists, given that Latin America
is becoming an integral part of global gas
trading, with imports rising in Chile,
Argentina and Brazil. Driving the
paradigm is the US LNG market, which
“has the potential of becoming the single
largest LNG producer in the world,” said
Todd Peterson, an advisor to US LNG
projects at Japan‟s Itochu Group.
Speaking on a January 15 panel at a
regional LNG forum in Houston, he
predicted that the US‟ Henry Hub
benchmark “could have quite an impact
on natural gas prices around the world.”
He said that was “going to help
develop LNG projects in the Caribbean,
Central America and South America and
around the world.”
FSU OGM
GLNG
LNG import potential
rising in Latin America
Argentina, Chile and Brazil could become larger importers of LNG, yet price will be key,
as there is competition from domestic production and pipeline imports
By Kevin Godier
Latin American countries require LNG to supplement their energy needs in the medium to long term
Mexico is importing LNG to deal with rising demand, falling domestic output and US pipeline bottlenecks
Imports to Latin America are forecast to rise by 10% per year until 2020, Cedigaz forecasts
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reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
Other panellists forecast that, even if
there is a marked rise in oil and gas
exploration and sales activity, many
Latin American countries will still
require LNG to supplement their energy
needs in the medium to long term.
Developing markets across the world
are energy-hungry, but the specific
growth in demand for LNG will pivot
upon a number of factors, including
pricing, politics and the level of
hydrocarbons imports needed, especially
by Brazil and Argentina. Together, these
two markets accounted for 2% of global
LNG imports in 2012, according to
International Gas Union data.
Brazil is, of course, focused upon its
huge pre-salt reserves and Argentina is a
potential producer from vast shale
reserves, and both markets will always
look very hard at the price of regional
pipeline gas, which averages between
US$1 to US$2 per million Btu.
LNG, by contrast, might be available
in a US$4-8 per million Btu range if
commodity prices remain at current
levels. However, analysts see the fuel
acting as a hedge if pipeline shipments
fall prey to politics. LNG could also
address seasonal and yearly supply
variations.
Brazilian imports
In both 2012 and 2013, Brazil was a
robust user of spot LNG to compensate
for the fall in hydropower owing to
drought conditions.
The trend has continued this month,
with ship-tracking data showing that the
Brazilian parastatal Petrobras received a
spot cargo in mid-January, which was
loaded out of storage from Portugal and
delivered to its floating regasification
terminal at Guanabara Bay, near Rio de
Janeiro.
Petrobras has another regasification
plant in the northeastern port of Pecem in
Ceara. Drought in 2013 left Brazil‟s main
hydro reservoirs at their lowest levels
since 2001, when the country had to
impose energy rationing.
Brazil‟s trade balance and Petrobras‟
bottom line were both hurt by the spot
cargoes, and the need to import large
amounts of gasoline and diesel earlier in
2013. However, Brazilian independent
HRT Participacoes em Petroleo
completed a study in 2013 that indicated
LNG might be the best way to bring to
market natural gas deposits found in the
country‟s remote Solimoes region, where
HRT has a 55% interest in 19 exploratory
blocks.
Imports into Argentina are also subject
to seasonal fluctuations and weather
conditions, but demand undoubtedly
exists. On January 15, Argentina‟s YPF
closed a tender for five cargoes delivered
to the country‟s Bahia Blanca and
Recalada ports, according to industry
media. The ports were built in 2007 and
2011 respectively. Argentina has no
long-term contracts to import LNG, but
by October 1, 2013, YPF and state-run
Enarsa had issued seven spot tenders
since December 2012, seeking as many
as 150 LNG shipments.
Of course Argentina sits on sufficient
gas reserves to provide self-sufficiency.
The US Energy Information
Administration (EIA) has estimated that
the nation sits on the world‟s second
largest shale gas reserves at 802 trillion
cubic feet (22.7 trillion cubic metres).
YPF is beginning to drill and develop
shale resources but it could take up to
four years to gain clarity, said Alejandro
Fernandez, operations manager for YPF's
gas and energy department.
“We don‟t have the crystal ball ... LNG
will stay for the next couple of years,” he
was quoted as saying by Upstreamonline
on January 16.
Mexican quest
Latin America‟s second largest economy,
Mexico, has been stepping up its imports
of LNG as rising demand, falling
domestic output and pipeline bottlenecks
for cheap US imports have sometimes
forced it to pay at least four times more
for added supplies.
In March 2013, an energy crunch in
Mexico underlined the country‟s growing
dependence on imports to keep power
flowing. State-run Pemex sought to buy
LNG at any price in order to avert
potential grid failures, paying a price of
US$19.45 per million Btu for a spot
LNG cargo in March, after imports from
the US costing about US$4.40 per
million Btu hit the limit of pipeline
capacity.
Mexico is likely to reduce its costly
imports towards the end of 2014 as major
pipeline expansion works allow more US
gas into the country.
Chile is another Latin American buyer,
as shown by state-run copper mining
company Codelco‟s recent agreement to
buy two cargoes of LNG for the
Mejillones LNG terminal in the north of
the country.
Chile began importing LNG in 2010,
but last year saw the scrapping of a
scheme to add 50% of capacity at
Mejillones because of lack of demand.
In Uruguay, the need for imported fuel
to run its power plants will decline, as
more than 132 MW of wind capacity is
expected to be installed by the middle of
2014, reaching 450 MW by the end of
the year. Nevertheless, GDF Suez has
begun work on the US$1.13 billion GNL
del Plata (Punta Sayago) LNG
regasification terminal, located offshore
of Montevideo, which is expected to
come on line as early as mid-2015.
Starting in 2015, GNL del Plata is
predicted to produce up to 10 million
cubic metres per day of regasified LNG,
supplying this to Uruguay‟s first
combined cycle power plant at Punta del
Tigre.
GNL del Plata will more than cover
Uruguay‟s demand, and so will be
positioned to export gas, particularly to
Argentina.
The world‟s fleet of LNG vessels are
undoubtedly making more stops than
ever in Latin America. Although the
region now only accounts for around 5%
of global LNG imports, it is anticipated
by market commentators to witness one
of the fastest rates of growth this decade.
Imports are forecast to rise by 10%
annually up to the end of 2020, according
to Cedigaz, a compiler of gas market
data. If there were a corresponding
recovery of the nuclear power business in
the world‟s leading LNG consumer,
Japan, the downward pressure on pricing
would greatly enhance the process.
GLNG
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reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
The reaction from the international bond
markets to Mexico‟s constitutional
energy reform has been positive, with
atypically high demand seen for new
borrowing from the government and
from state-run Pemex.
Yet the response to the reforms within
Mexico itself remains mixed. The lower
prices and economic benefits promised
by the reform are years away from
becoming a reality, assuming they do
actually materialise. And the legislative
sessions starting in under two weeks will
have to tackle the laws that will enact the
constitutional changes and allow foreign
and private companies to explore for and
produce oil and gas in Mexico for the
first time since 1938.
Bond success
Pemex set records last week by
borrowing US$4 billion from the
international bond markets, the largest
ever by any company from an emerging
market. The company found investors for
three bonds – US$3 billion due in 2043,
and US$500 million each for five-year
and 10-year bonds. It had initially
planned to borrow just US$2 billion
worth of 30-year bonds.
The firm usually makes its largest
bond market forays in January, when
bond funds are usually flush with cash
from new allocations.
A week earlier the government had
placed US$4 billion worth of bonds with
investors, meaning Mexico as a whole
has been able to tap US$8 billion of
investor demand in 10 working days; a
rare feat. Demand was no doubt spurred
by the December decision by credit
ratings agency Standard and Poor‟s to
boost ratings for both the government
and Pemex to BBB+ from BBB.
Typically, the most watched increase is
to BBB- from BB+, a measure that lifts a
borrower out of junk into investment
grade. This opens the door to a vastly
larger number of investors, because so
many funds are barred from investing in
junk-rated companies.
Standard and Poor‟s specifically cited
the December 20 approval of a
constitutional reform that ended Pemex‟s
monopoly on oil and gas exploration as a
key reason for boosting ratings for both
entities. When upstream investment
begins to flow in, which the Mexican
Energy Ministry estimates will start in
late 2015 or early 2016, it will represent
a significant macro-economic boost for
the country and additional revenues for
the federal government.
There are also financial market drivers
stabilising domestic and company
borrowing. Mexico created a system of
private pension funds, which have a
mandate for investing in peso-
denominated debt, switching from a
central government pay-as-you-go
system. The rising pool of workers‟
pension deposits has been meant lower
interest rates and more exchange rate
stability for the government and state-
backed companies, which suffer less
when there are sudden moves in peso-
dollar rates. This was a factor that helped
trigger a debt crisis and a vicious circle
of financial collapse between 1994 and
1995.
Reform push
Attention has now shifted to two factors
– the secondary laws that will contain the
nuts and bolts of how new companies are
to participate, and which fields Pemex
will seek to hold on to via its so-called
“round zero”; in which it has first refusal
on all existing resource-bearing blocks.
Transitory articles demand that the
ruling Institutional Revolution Party
(PRI) pass the second phase of energy
reform within three months of the
constitutional reform. The PRI has said
publicly that it intends to change 23 laws
to enable the direct licensing of resource-
bearing blocks, the sharing of resources,
production or profit, or combinations of
the above.
Pemex must claim its round zero
blocks by March 21 sending detailed
plans of how it intends to produce from
the fields it wants to keep under the
control of the National Hydrocarbons
Commission (CNH), the energy
regulator.
Pemex has so far made it clear that it
wants to hang on to its Bay of Campeche
fields, which delivered around 80% of
the firm‟s output in November.
It is also expected to offload low
margin natural gas fields so it can focus
on higher-margin deposits, a position
reiterated by Pemex‟s director general,
Emilio Lozoya Austin, at several public
events since last April.
LatAmOil
International investors give
thumbs-up to Mexican reforms
International investors have rushed to snap up new bonds issued by the Mexican
government and Pemex in a sign of confidence in the country‟s energy reform
By Amanda Beard
Pemex borrowed US$4 billion from international bond markets last week
The government also placed US$4 billion worth of bonds with investors
The reform process will gather momentum in February when the proposals go before the legislature
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Copyright © 2014 NewsBase Ltd.
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All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
“People will be asking how the round
zero will be implemented,” Rogelio
Lopez Velarde, a partner in Lopez
Velarde, Heftye and Soria, a law firm in
Mexico City that specialises in energy,
told NewsBase. “Pemex has to prove why
it should keep the fields based on their
capacity.”
A key question will be whether Pemex
will be allowed to keep fields where it
lacks capacity on its own, based on the
argument that it will be able to find a
skilled collaborator via its own tender or
a negotiated partnership.
“It could be that the government will
insist that they enter an open tender with
their proposed joint venture partner,” he
added. Since the rules have not yet been
made public or passed by the legislature
and regulators have yet to publish their
views on those topics, the round zero
decisions look set to be a watershed
moment for potential participants.
Mexico‟s legislature reopens in
February and the Revolutionary
Democratic Party (PRD), which
staunchly opposes the reform, is seeking
to add a referendum on the reform on to
mid-term ballots. It is improbable that
Mexico‟s politicians would yield to the
referendum‟s results, but the issue
remains highly divisive and is likely to
bring PRD supporters out onto the streets
in protest.
Furthermore, PRI deputies in marginal
constituencies could choose this
legislative session to pressure the party to
narrow the proposed opening up of the
market suggested by the constitutional
reform in order to defend their seats.
Such political concerns are unlikely to
derail the project, though, a fact
emphasised by the appetite amongst
international investors for Pemex and
Mexican government bonds.
It is no secret that the statements of
politicians should often be taken with a
pinch of salt.
But even so few observers have
doubted that the announcement that oil
from the Kurdistan region of Northern
Iraq was flowing to Turkey‟s
Mediterranean oil hub at Ceyhan meant
anything less than that oil exports would
begin sooner rather than later.
The more so after the Kurdistan
Regional Government (KRG) announced
its plans to export 2 million barrels in
January, rising to 4 million in February
and 10-12 million by the end of the year,
after operator Genel Energy announced
that it was ramping up production and
even less so after the Iraqi central
government in Baghdad warned that it
would respond to the start of exports by
taking legal action against shippers,
buyers and against Turkey.
Which meant that the statement by
Turkish energy minister Taner Yildiz last
week confirming that only around
180,000 barrels of Kurdish crude had
been pumped to Ceyhan despite the
pipeline – which was expected to carry
up to 400,000 barrels per day – being in
operation for close to a month, all the
more surprising.
Piping problems
Turkish officials were able to explain
that the unusual nature of the Kirkuk-
Ceyhan pipeline has meant that to date
little Kurdish oil has been able to be
pumped. The line consists of two parallel
pipelines of 40-inch (1.01 metres) and
46-inch (1.17 metres) diameter
respectively both of which were
constructed to carry crude from the
Baghdad-controlled Kirkuk oilfields.
LatAmOil
Downstream MEA
Kurdish export plans currently
little more than pipe dreams
Technical issues mean that the volumes of Kurdish crude arriving at Ceyhan are far lower
than have been suggested, and an agreement with Baghdad now looks to be essential if
they are to increase
By David O’Byrne
Despite weeks of claims, it appears that a paltry 180,000 barrels of Kurdish crude have reached Ceyhan
The Turkish terminal has not been able to deal with the different crude blends, creating a choke point
With the cork still in the bottle, progress appears impossible without talks between Baghdad and Erbil
Turkish officials were able
to explain that the unusual
nature of the Kirkuk-
Ceyhan pipeline has meant
that to date little Kurdish
oil has been able to be
pumped
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reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
Now while the 40-inch line has been
co-opted to carry Kurdish crude, the two
lines still feed into the same pipeline
network at Ceyhan meaning that it is
only possible to fill the Ceyhan storage
tanks from one line at a time without
mixing crude from the two lines.
As the crudes carried by the two lines
have a different specific gravity, mixing
is not an option. And as Turkey has
contracted obligations to Iraq to carry the
Kirkuk crude, it has been obliged to
allow Kirkuk crude to flow into the
Ceyhan tanks with Kurdish crude only
able to flow for a few hours a day during
periods when Iraqi flow is halted for
maintenance on the Iraqi section of the
line.
So assuming Yildiz‟s statement is
correct, with little Kurdish crude flowing
there seems little danger of Turkey
reneging on its promise of not allowing
the export of Kurdish crude until a deal
has been brokered between Baghdad and
the KRG in Erbil. But this does raise
some questions. Firstly, why would
Turkey and the KRG have been so keen
to give the impression that exports were
imminent? Turkey must have known in
advance that flow would be limited while
the KRG must have been aware that
flows were far lower than the volumes
needed to make their planned exports.
That would appear to be a simple ploy
to force Baghdad to conclude a deal
rather than be left with a fait accompli –
predictable and hardly surprising.
Equally unsurprising given Baghdad‟s
history of intransigence on the issue, it
has failed to produce anything more than
threats of litigation.
Ceyhan chokepoint
Secondly though, there has been plenty
of warning from both the KRG and
developers in the region that they want to
export through the 40-inch Kirkuk-
Ceyhan line. One developer – Genel
Energy – has completed a line from its
producing field to connect with Kirkuk-
Ceyhan and two more are reported to be
under construction.
So why has no work been done at
Ceyhan to allow crude from the two
pipelines to be tanked separately and
simultaneously? This is less clear. It
could be that it just did not occur to
anyone in Ankara to check the specs of
the Botas Ceyhan terminal to find out
what was possible. The cock-up theory of
history is an enduring one but given the
age of the terminal and experience of
Botas personnel who run it, it seems
unlikely it would have escaped notice.
It could be that the work would be
difficult to complete without alerting
Baghdad as to what was happening, or
that the Iraqi government has some sort
of veto over such work being undertaken
on the line.
This though would imply that Baghdad
should be aware of the technical
bottleneck, which apparently it was not.
Pipeline politics
More interesting perhaps is the question
of why Ankara chose now to confirm the
problem and expose the KRG‟s export
plans as unfeasible. This strongly
suggests some level of dissatisfaction
with the KRG‟s apparent preference for
baiting Baghdad rather than actually
trying to negotiate an agreement.
Yildiz announced before Christmas
that Baghdad and the KRG had decided
to settle the issue between them, without
the help of Ankara.
But those talks do not seem to have
actually commenced until around two
weeks ago with only three meetings
having apparently taken place.
Whatever the truth, the fact now
appears clear that with currently no
possibility of operating both pipelines
simultaneously without the two crudes
being mixed in the tanks, any agreement
between Baghdad and the KRG to allow
exports to start would have to be for a
blended crude, at least until such time as
new pipes can be added to allow
separation and simultaneous flow – a fact
that will be sure to further complicate
negotiations and may have wider
implications for buyers used to buying
Kirkuk crude.
Downstream MEA
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reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
November‟s interim agreement between
Iran and the P5+1 was a watershed in
relations between the international
powers and the maverick Islamic
Republic.
While recent news reports have set out
conflicting interpretations of that
agreement, and the likely implications
once the real work of a possible complete
dismantling of sanctions begins, should
Iran comply with their demands, many
companies, some with previous business
experience in Iran, stand to gain if
sanctions are eased further.
When the interim agreement ends in
May, the question of progress in the goal
towards Iranian compliance will be
thrown into relief. Iran insists that its
nuclear programme exists to provide
conventional power, but sceptics, such as
Canada, Saudi Arabia and Israel, remain
unconvinced. Understanding the scope of
the sanctions, and the implications of
their removal, is key.
Key concepts
In December 2013, Patrick Murphy, legal
director at Clyde and Co., gave a
presentation in Dubai outlining the nature
of international sanctions against Iran.
He said that the brunt of the measures
had been introduced by the US and the
European Union, and that with interim
relief being offered in November, time
had come for a reassessment of where
their possible removal might lead.
The key aspect of US sanctions,
broadly in place since the return of
Ayatollah Ruhollah Khomeini to Teheran
in 1979, is a denial of the machinery of
the US dollar-denominated banking
system to Iran. EU sanctions are much
more recent, with a new raft imposed in
2012, but appear to be just as effective.
Murphy said the November deal meant
no new sanctions would be imposed for
six months, and involved the lifting of
embargoes on gold and precious metals,
Iran‟s automotive sector and the
country‟s petrochemical exports. The
licensing of safety-related repairs to
Iranian airlines was also allowed.
Some restrictions on Iran‟s vital oil
sector were lifted: the deal allowed
purchases of Iranian crude to remain in
force at current levels – amounting to a
60% reduction on 2012 – and that the
proceeds from such sales could be
repatriated back to Iran up to limit of
US$4.2 billion. There also seemed some
likelihood of the lifting of prohibitions
on insurance of the transport of those
crude sales.
Renewed optimism
An Iranian official speaking at TOC
Container Supply Chain Middle East
underlined Iran‟s efforts to capitalise on
the new optimism by setting out a list of
tenders for port equipment required at
Bandar Abbas.
Port representative Behzad Alsafi said
Bandar Abbas would be bidding for
several items of equipment and
technology, including vessel traffic
monitoring systems, automated ship
mooring systems, cameras, access
control identification and container
inspection technology. Another Iranian
official attending the conference in Dubai
expressed pessimism about the chances
of a long-term deal being brokered in
May. “I don‟t think anything‟s going to
change,” he said.
Energy expert Justin Dargin, of the
University of Oxford, is more optimistic,
sensing that the time is ripe for change.
He told NewsBase: “Without a doubt,
increased incremental removal of
sanctions appears to be quite likely in the
near future, as Iran has continued its
good faith steps. The latest negotiations
that occurred with the election of Hassan
Rouhani created a much more conducive
environment to move to rapprochement
between Iran and the Western powers.”
He said that the sanctions relief in the
Geneva agreement was a significant first
step.
“Arguably, the most important aspect
of the sanctions suspension in the
precious metals, petrochemicals and
vehicle industries is that on the energy
sector. It grants potential Iranian
customers the optimism that a
comprehensive agreement is around the
corner and that they can begin to
negotiate with Iran over substantially
increasing its exports to their markets in
the short to [medium] term.”
Taking steps
Recently, he said, Iran has begun to
disconnect centrifuges at Natanz plant,
and it has started to curb some of its most
sensitive uranium enrichment as well.
MEOG
Iran’s future growth hinges
on sanctions decision
There is plenty of optimism that Iran‟s energy sector can grow if Western-backed
sanctions are lifted. The issue now appears more one of „when‟ rather than „if‟
By Peter Shaw-Smith
Optimists are hopeful that Iran's energy sector is due for an investment boom
The country’s oil and gas fields are in dire need of foreign technologies to increase recovery rates
With sanctions now being eased, Tehran is whipping up interest among IOCs
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NRG January 2014, Issue 46 page 19
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
The International Atomic Energy Agency
(IAEA) has concurred, he believes, that
Iranian progress is authentic, and has
announced that Iran has indeed halted
uranium enrichment above 5% purity at
both the Fordo and Natanz plants.
“If Iran continues, which is quite
likely, its steps to fulfil the elements of
the nuclear agreement, a partial
regeneration of the Iranian energy
industry would likely take place within
the year. It is partial in the sense that Iran
still needs to upgrade its energy-related
infrastructure, and that would take a
longer time. The restrictions on the
insurance and transport of Iranian oil by
American and European companies are
anticipated to be removed soon as well.”
Not every country is supportive of the
framework of negotiations, Dargin said.
“For instance, Canada, Israel and Saudi
Arabia tend to view the Iranian intention
to negotiate as being a cover to continue
to develop nuclear-weapon technology,
and as a result, Canada vowed not to
remove sanctions.”
Sanctions dance
Unsurprisingly, Iran has sought ways to
avoid the sanctions, and in particular,
directed its global oil trading effort
eastwards, in order to step up deliveries
to countries such as China, Japan, South
Korea and India, which were explicitly
allowed to trade with Iran, although not
to make payment in US dollars, because
“US banks are prevented from
facilitating transactions with Iran”, noted
Murphy. “In order to work around
sanctions, Iran developed a multifaceted
strategy to forestall total economic
breakdown. These strategies were both
short-term and long-term in scope, as
Iran had expected the sanctions regime to
last for some time. Iran offered
significant discounts on its crude exports
to its Asian customers in a bid to get
them to break Western sanctions. This
was part of its overall strategy to rely
more upon the Asian market instead of
the Western market,” Dargin said.
“Additionally, Iran moved to expand
the role of the private sector in the export
market. This was thought by the
leadership to provide a means to bypass
sanctions that were aimed at
governmental agencies. Iran also created
numerous front companies or traders for
export in a bid to evade surveillance.
Moreover, at one point, Iran was
estimated to be storing between 26 to 30
million barrels of oil on its super-
tankers.”
One of the most pressing issues for
Iranian shipping has been the denial of
insurance cover from international
underwriters during the sanctions regime.
As a means to reassure its customers,
Iran created sovereign-backed
reinsurance companies in order to resist
sanctions directed towards its global
shipping network and that of shipping
networks from countries that imported
from Iran, Dargin added. “This move
was not that successful, as the funding
offered was not in line with global
standards,” he said.
Looking downstream
Iran has looked beyond oil exports to its
downstream industry to provide succour
in its time of need, Dargin said.
“As a long-term strategy, Iran sought
to reduce dependence on crude oil
exports through the expansion of the
downstream industry. This was thought
by the Iranian leadership to provide, on
the one hand, more revenue stability and
job creation, and would also reduce the
dependence of Iran on the vagaries of the
Western oil market.”
Iran requires massive investment in its
economic sectors that were hit by
sanctions, he said.
“In particular, the oil and natural gas
sectors are in horrendous shape. As
Iran‟s oilfields are mostly mature, Iran
needs the latest oilfield technology in
order to improve reservoir production
rates. The technology that Iran requires
includes more advanced drilling
equipment, equipment to maintain
pressure in more mature oil wells, as well
as some of the latest seismic imaging
technology.”
Iran‟s 2,800-km coastline is served by
13 major commercial ports. “Iran is in
dire need of port refurbishment. Some of
Iran‟s Asian customers, such as India and
China, have offered generous loans to
refurbish Iran‟s ports that would buttress
its exports to the Asian markets. As an
example, the somewhat decrepit port of
Chabahar, which is essential for Asian
exports, has been the source of interest
from India to provide significant upgrade
and expansion,” Dargin said.
He suggested that Iran could return to
some kind of normality in the near
future.
“As the sanctions were just suspended,
it will take a bit of time for Iranian
exports and imports to reach full
capacity. Additionally, not all sanctions
have been lifted. As Iran was shut out of
the global banking sector for some time,
it will take some time for international
customers to begin to reintegrate
payments to Iran as well,” he said.
“The most important issue is the ability
for Western companies to trade in the
Iranian petrochemical sector. However,
the ultimate impact is likely to be limited
in scope, as prior to the imposition of
sanctions most of Iran‟s petrochemicals
exports went to the Asian market,” he
noted. “Nonetheless, the partial removal
of some of the Iranian sanctions has
allowed Iran some breathing room with
the expectation that exports and imports
will substantially increase to head
towards the pre-sanctions level within a
period of months.”
Despite his optimism, Dargin is under
no illusions about the way forward.
“Suffice it to say, much of the interim
progress depends on the success, or lack
thereof, [of] a final agreement.”
MEOG
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NRG January 2014, Issue 46 page 20
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
The ongoing debate on the comparative
safety of rail and pipeline transportation
of crude oil has been re-ignited after the
train derailment and fire that led to the
evacuation of a North Dakota town in
late December.
Coming as the US moves nearer to a
decision on whether to approve the
Keystone XL pipeline, the incident
involved the crash of a 106-tanker BNSF
train carrying crude east from the Bakken
shale, which collided with another BNSF
train that was carrying grain near the
town of Casselton, about 25 miles (40
km) west of Fargo. Public safety officials
urged the evacuation of more than 2,000
residents as a fire engulfed the oil tankers
and burned for over 24 hours. The train
carrying oil originated in Fryburg, North
Dakota, and was bound for Hayti,
Missouri, on the Mississippi River.
Although no injuries were reported, the
incident marked the fourth major North
American derailment in six months
among trains transporting oil, and has
generated widespread calls for new and
enhanced safety features for crude oil
tankers. The North Dakota crash is “a
wake-up call for what increased oil
production in North America is going to
mean” for US communities, said Oil
Change International‟s executive
director, Stephen Kretzmann. The
Washington-based group opposes the use
of more fossil fuels.
According to Consumer Energy
Alliance‟s executive vice president,
Michael Whatley, more rail accidents can
be expected with the greater use of trains
to carry oil to market. “Trains need to be
a supplement, not a replacement” for
pipelines, Whatley was quoted on
January 1 by Bloomberg as saying.
While both forms of transportation are
safe, in that there are very few incidents
relative to the amount of crude they
transport, “we need expanded pipeline
infrastructure,” he said. Consumer
Energy Alliance is an industry-backed
group that supports Keystone XL.
Record levels of North American oil
are now being moved by rail as US crude
output has hit its highest level since
1988, driven mainly by shale formations
in Texas and North Dakota. Canadian
production – primarily from Alberta‟s oil
sands, is also on the rise. At the same
time, plans for new pipelines have stalled
and existing infrastructure has struggled
to keep up with surging output. The
recent accident will intensify scrutiny of
the safety and environmental risks that
are involved in rail transportation, and
will likely renew questioning of whether
pipelines may be a safer shipping
method.
Some believe that the accident may yet
play out in favour of the proposed
US$5.4 billion Keystone XL, which
would run from Canada to the US Gulf
Coast. The pipeline would primarily
carry oil sands crude, but it would also
receive about 100,000 barrels per day of
light oil from the Bakken formation in
Montana and North Dakota.
NorthAmOil
Rail accident sharpens focus
on crude transportation
Another crash involving a train carrying oil has intensified the debate on the comparative
safety of crude transportation by rail and pipeline once again
By Kevin Godier
A number of major accidents involving oil trains have occurred in recent months
The comparative safety of pipelines and trains feeds into the greater debate on the Keystone XL project
There are concerns that Bakken crude may be more flammable and requires extra safety measures
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NRG January 2014, Issue 46 page 21
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
US President Barack Obama is
expected to rule definitively on the
1,179-mile (1,897-km) pipeline within
the next few months, when the US
Department of State (DoS) will have
completed work on a report that will
weigh up the project‟s environmental
impacts.
Pipelines vs trains
A growing part of the Keystone XL
debate has been on the relative safety of
pipelines versus trains. The evidence to
date has not proved conclusive, with
some suggesting that oil pipelines are
generally safer, with pipeline accidents
having resulted in fewer injuries, but that
they have a higher risk of leaks and spills
than trains. Meanwhile, in March 2013, a
draft supplemental environmental impact
statement released by the DoS indicated
that while derailments probably would
release less oil than a pipeline rupture,
trains have an “increased statistical
likelihood of spills”.
Opponents of Keystone XL have
pointed to pipeline spills that have
recently occurred in Alabama, Michigan
and North Dakota, citing the risk
involved in major projects in particular.
Further concern has been caused by the
fact that two pipelines carrying oil sands
crude from Canada have ruptured in
recent years. Train accidents have also
been prominent, though. A train carrying
oil to the Gulf Coast from North Dakota
derailed in Alabama in November 2013,
triggering fires. A month earlier,
residents were evacuated from a rural
area of Alberta after 13 rail tankers, four
of which were carrying crude, derailed
and also ignited. The worst accident
occurred in July, when a runaway train
transporting crude exploded and killed 47
people in the Quebec town of Lac-
Megantic. In addition, following the
recent crash in North Dakota, a CN train
carrying crude and LPG was reported to
have derailed in New Brunswick in early
January, resulting in a fire and the
evacuation of 150 people nearby.
Pipelines have an additional advantage
in that they generally cross more sparsely
populated regions, whereas there are
more rail lines going through more
populated areas. Costs are also a factor
for companies. It currently costs about
US$7 to transport a barrel of oil from
Alberta to the US Gulf Coast by pipeline.
This is slower than if the oil were
transported by rail, but is also cheaper,
with rail transportation costing between
around two to four times as much.
Developers of several major North
American pipelines awaiting approval
decisions will be watching the unfolding
debate with keen interest. As well as
Keystone XL, notable projects include
Enbridge‟s C$6 billion (US$5.5 billion)
Northern Gateway and its Line 9B
reversal, TransCanada‟s C$12 billion
(US$11 billion) Energy East project and
Kinder Morgan‟s Trans Mountain
expansion.
North Dakota relies on both methods
to transport its crude, as the growth of
output from this remote area has
outstripped pipeline capacity. The state
produced nearly 950,000 bpd of oil in
October. Roughly 700,000 bpd of this
was reportedly shipped by rail, most of it
consisting of the light, sweet Bakken
crude that safety officials are now saying
could be particularly flammable, because
of its high propane and butane content.
Almost 2,500 miles (4,023 km) of new
pipelines were also built in North Dakota
in 2012, and the state has been
encouraging midstream operators to
expand the network to keep pace with
record production in the oil patch. North
Dakota now has about 17,500 miles
(28,164 km) of pipelines. However in
September, a Tesoro pipeline ruptured
and spilled 20,000 barrels of crude at a
remote rural site in northwest North
Dakota, which is the US‟ largest oil-
producing state behind Texas. This led to
the revelation that North Dakota had
recorded almost 300 small oil spills in
under two years but that these had gone
unreported to the public.
New approach?
Although rising output has driven North
Dakota‟s unemployment rate down to the
lowest in the US, calls for a slowdown in
the state‟s oil production have been
voiced in some quarters. The chairman of
North Dakota‟s Republican Party, Robert
Harms, who is also an energy industry
consultant, told Reuters on January 2 that
a “moderated approach” was required.
“Even people within the oil and gas
industry that I‟ve talked to feel that
sometimes we‟re just going too fast and
too hard,” said Harms.
Surging output is forecast to propel the
US past Saudi Arabia as the world‟s
largest oil supplier in 2015, and there are
many doubts over whether the safety
debate will ultimately hold back the rise
of crude by rail, in which shipments have
soared from less than 5,000 tanker loads
in 2006 to an estimated 400,000 in 2013.
Petroleum products were the fastest-
growing category of rail shipments in
2013, the Association of American
Railroads (AAR) said in a recent report.
This indicated that the volume of
shipments rose 31% last year, while
overall traffic rose 1.8%.
The topic of rail safety will not go
away. Regulators are actively seeking
public input on proposed updates to old
crude-by-rail rules covering tanker
toughness and other standards. However,
the commercial pressures are immense.
Against the slow pace of pipeline
approvals, the dynamic crude-by-rail
market looks set to keep growing, as
shown by the number of crude producers
and coastal refiners that have committed
to multi-year contracts to transport
Bakken crude by rail. Indeed, a reported
manufacturing backlog of about 60,000
oil tankers is slated for delivery by 2015,
which makes it inevitable that further
accidents will occur as North America‟s
hydrocarbons industry continues its
learning curve.
NorthAmOil
“Even people within the oil
and gas industry that I’ve
talked to feel that
sometimes we’re just going
too fast and too hard”
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NRG January 2014, Issue 46 page 22
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
Germany‟s attempts to increase its
renewable energy capacity massively
have thrown up another illustration of the
uneven pace of development.
The European leader in renewable
energy capacity and its neighbour, the
Czech Republic, are to regulate power
flows across their borders so that surges
in the amount of German clean energy do
not overload the Czech grid and increase
the risk of power cuts. A similar deal is
likely to be signed between Germany and
Poland later this year.
Prague and Berlin have agreed to
install phase-shifting transformers along
their border with the aim of making
power trading between the two countries
smoother and boosting the security of
supply in the Czech Republic.
The transformers are an unforeseen
result of the massive expansion of wind
energy assets in the north of Germany –
where the country‟s best wind
resources are located – and the
need to transport that power to
the main centres of population
and demand in the industrial
south of the country.
Interconnection
While a large amount of
generating capacity has been
built – in November last year,
some 60% of demand was being
met by renewable sources at
certain times – Germany‟s grid
infrastructure has not kept pace.
A new power line between
Schwerin in the east of the country and
Hamburg was opened in 2013 but only
after years of delays, and any further
upgrades will be similarly slow to
emerge. Eventually, a new link from
Thuringia in the east of Germany to
Bavaria will solve the capacity problems,
but the 250 million euro (US$342
million) link is not expected to come on
line for another two to four years.
The result is that if Germany wants to
transmit renewable power to Bavaria, it
sends it via its eastern neighbours, which
distorts their ability to trade power with
other countries and threatens to overload
their grids. Both Poland and the Czech
Republic have threatened to shut down
their links to Germany when it is very
windy, typically in the latter part of the
year.
The Czech Republic‟s position at the
heart of Europe means it has five
interconnections that make it a natural
transit point for power trading in the
region. CEPS, the Czech transmission
system operator (TSO), explains:
“Electricity flows along the path of least
resistance, consequently, a significant
proportion (up to 50%) of electricity
exports from Germany to Austria flows
through Poland and the Czech Republic
since this path offers less resistance than
a more direct path through the internal
German network.”
The result is that these surges of
mainly wind-derived electricity make
balancing power in the Czech grid
difficult, although not impossible. CEPS
says: “The installation of the phase
shifters will significantly improve control
of unplanned flows on the
interconnector.”
While the immediate cause of the
problem is the lack of internal
transmission infrastructure in
Germany, it is not helped by
infrastructural weaknesses in its
neighbours and it illustrates the
inefficiencies thrown up by
Europe‟s lack of a single
electricity market.
Market rates
If there were a (true) single
market, then Germany‟s cheap
wind energy would be bought by
its neighbours when it was
available, reducing prices for
consumers as well as helping to
decarbonise the system overall.
REM
Phase-shifting the
blame in Central Europe
The Czech Republic and Germany have agreed to install phase-shifters to regulate
transmission, but this may be ignoring a wider problem – the lack of a single EU market
By Mike Scott
Both Poland and the Czech Republic are to control their cross-border transmission from Germany
However, with a true single market, electricity tariffs could be lower and savings passed to consumers
This market would require better investment in transmission and infrastructure, slated for 2016 onwards
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NRG January 2014, Issue 46 page 23
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
However, because power markets
remain defined by national borders,
consumers are losing out on such
substantial efficiencies and economies of
scale. As it is, national power companies
have incentives to stop cheap power from
neighbouring countries reaching
consumers because it reduces the
profitability of their own generating
capacity.
The EU is aiming for the single energy
market to be completed in 2014, but it
seems a forlorn hope. EU member states‟
energy systems are characterised by a
range of different market mechanisms,
regulatory and tax regimes and
technology mixes. Finally, national
politicians guard their countries‟ energy
independence jealously.
So even though, as the Agency for the
Co-operation of Energy Regulators said
recently, delays to the single market for
electricity are costing consumers billions
of euros, many providers are in no hurry
to make it a reality.
According to the chair of ACER‟s
board of regulators, Lord Mogg, “The
advantages brought about by the single
market, such as lower wholesale
electricity prices or a more efficient use
of interconnectors identified in the study,
still have fully to benefit final consumers
in the retail market.”
Yet a single energy market will be vital
for markets looking to exploit their
renewable resources fully, such as
Scotland, Portugal, Ireland and Romania,
which will be able to produce far more
energy than they consume – but will only
benefit from this if they have someone to
sell the energy to.
Northern Europe
Some progress is being made,
particularly in Northern Europe, where
the UK has interconnectors in place with
Ireland, France and the Netherlands, with
plans under way for a link with Norway
– which is also strengthening links with
Denmark and Germany.
Norway, with its abundant fast-
reacting hydropower capacity, could play
a crucial role in integrating the wind
resources of the North Sea into a Europe-
wide system by acting as a kind of
battery for Europe – providing stand-by
power to compensate for fluctuations in
the contribution of variable renewable
energy.
At the moment, though, the focus
appears to be on mollifying incumbent
producers rather than on securing
cheaper power for consumers. Placing
the blame on “unreliable” German wind
energy shifts blame, rather than
addressing the wider problems of the
market – to the detriment of further
renewables development.
Chinese shale gas production witnessed a
surge in 2013, climbing five-fold to 200
million cubic metres, according to
China‟s Ministry of Land and Resources.
The government has pledged to spur the
shale industry‟s development and meet
rising gas demand by prioritising land
approvals, allowing tax-free imports of
equipment and offering subsidies to
explorers.
National Energy Administration
(NEA) deputy head, Zhang Yuqing, said:
“We will continue to work closely with
other departments to reduce problems
regarding government policies and other
regulations reflected in the development
of shale gas, and create a better
environment for shale gas producers.”
Beijing has set an ambitious target of
boosting the country‟s shale gas output to
6.5 billion cubic metres per year by 2015.
The Five-Year Plan, which runs from
2011 to 2015, includes not just
exploration and production but also
transportation and infrastructure, which
China is currently struggling with.
The pipeline network is widely
acknowledged to be insufficient to
transport such huge quantities of gas and
the country‟s terrain makes it even more
difficult to lay any pipelines. This, says a
report released by Kuick Research, will
require huge levels of investment in the
future.
Another problem is the lack of water
supply, as hydraulic fracturing requires
large amounts of water.
Vast resources
Beijing is confident, though, that it will
achieve its shale goals. Kuick describes
the country as “basking in the glory of its
recent world‟s largest shale finds.”
REM
Unconventional OGM
China makes shale progress
China‟s shale gas production reached 200 million cubic metres last year and there are
signs of increasing optimism over the unconventional sector, despite some challenges
By Nnamdi Anyadike
China has the world's largest shale reserves and ambitious targets, but development has been slow
Obstacles include challenging geology and a lack of pipeline infrastructure
Beijing is stepping up efforts to encourage shale development
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NRG January 2014, Issue 46 page 24
Copyright © 2014 NewsBase Ltd.
www.newsbase.com Edited by Anna Kachkova
All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All
reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents
The US Energy Information
Administration (EIA) reduced its
estimate of Chinese technically
recoverable shale reserves from
1.275 quadrillion cubic feet
(36.1 trillion cubic metres) to
1.115 qcf (31.6 tcm) of of gas,
but China nonetheless remains
the largest holder of shale
resources globally.
China‟s enormous shale gas
resources have been mainly
found in the Sichuan and Tarim
Basins, but other shale deposits
are also scattered all over the
country. Generally, however, the
reserves can be divided into four
regions – North China, South
China, Northwestern and
Northeastern China.
The exploration of shale gas in China
is still in its infancy and concerns were
expressed last year over the pace at
which development was proceeding,
amid speculation that the country would
fail to meet its 2015 production target.
However, exploration is picking speed
and Royal Dutch Shell recently
announced that the exploratory results in
the Sichuan Basin were satisfying.
Sinopec, the country‟s largest refiner,
has set a target of 3.2 bcm in 2015 for its
shale gas project in the Chongqing-
Fuling area, which is almost double its
previous target.
Slow progress
There are still concerns, though, that
government targets may be hard to reach,
as development thus far, despite last
year‟s progress, has been slow. A
National Development and Reform
Commission (NDRC) researcher, Zhang
Yousheng, recently raised doubts as to
whether the goals could be achieved –
much of which rest on domestic
companies PetroChina and Sinopec.
A recent analysis by Forbes was also
pessimistic, saying that the shale gas
revolution would “not be coming to
China anytime soon.” The report draws
on US Secretary of Energy Ernest
Moniz‟s visit to China at the end of 2013,
where he met government officials and
oil industry executives. Moniz pointed to
China‟s “above-ground issues” with
bringing gas to market, which mean that
the country lags behind the US.
“It‟s often forgotten that in the US not
only did we have obviously a favourable
geology for producing these resources,
but we also had by far the most mature
natural gas infrastructure in terms of
pipelines, market structures, trading
hubs, futures contracts, regulation of
production, etc.,” he said. For China to
develop its resources “at a large scale and
in a rapid fashion”, he said, it must tackle
these issues.
Unlike in the US, where independent
producers drove the shale revolution,
taking on risks that oil majors declined,
in China the three giant state-run oil and
gas companies have monopoly power
and developers with North American
shale expertise can only enter the sector
through partnerships with them.
Although China has set ambitious
targets for natural gas production, the
above-ground framework – including
regulations on how much cities will pay
to gas suppliers – still needs to be
adjusted to account for shale
development.
Gas use in China is
anticipated to double between
2010 and 2015 to 230 bcm and
domestic output is growing
slowly, which means more
imports are required,
predominantly from Central
Asia and Russia.
“Judicious investment in shale
gas might change the balance,”
said Forbes, although it added
that there would likely emerge a
gap between China‟s desire for
cleaner-burning fuels and its
ability to source them.
Growing interest
Nevertheless, China‟s shale
prospects are sufficiently appealing to
invite foreign companies to take a look at
what is on offer.
In early January, the Financial Times
reported on the Scotland-based Weir
Group – a leading manufacturer of
pumps used for fracking. Weir‟s CEO,
Keith Cochrane, told the paper: “It‟s
going to be a long time before China
reaches the US level. But there‟s no
question they are serious.” It is thought
that as development takes off, China
could become a sizable market for
companies such as Weir.
Other international oil firms including
ExxonMobil, Chevron, ConocoPhillips,
Shell, Total and Eni have already entered
into agreements to explore China‟s shale
resources. Services firms, such as
Schlumberger, Halliburton, Baker
Hughes and Weatherford, have also
increased their presence in China.
The rest of the world has been warned
not to underestimate China‟s
determination to launch its shale gas
sector. Beijing has been said to be fully
aware of the challenges involved, and is
taking steps to solve them. China‟s
political will is expected to help
accelerate development despite the
obstacles the shale sector is facing.
Unconventional OGM
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NRG January 2014, Issue 46 Back Page
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HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK
Oil and Gas Sector
AfrOil Vanoil appears set to lose its Kenyan licences after failing
to satisfy its contractual commitments.
AsianOil Myanmar may award 30 offshore licences this month.
ChinaOil PetroChina plans to invest US$250 million in drilling up to
30 shale gas wells in Sichuan this year.
FSU OGM Gazprom is reportedly close to a deal with Greece's DEPA
on gas price cuts.
GLNG Japan’s Toho Gas has signed a deal to take 300,000
tonnes per year of LNG from the Cameron LNG project.
LatAmOil Malaysia’s Petronas is considering investment in
Argentina’s Vaca Muerta shale play.
MEOG Aramco expects to begin the prequalification process for
EPC contracts for its Khurais field expansion in mid-2014.
NorthAmOil XTO Energy has struck two separate deals in the Utica
shale and Permian Basin.
Unconventional OGM Suncor Energy has reportedly suspended its plans to
develop its Montney shale acreage in British Columbia.
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