2. Independent energy consultant Gina
Cohen said that, although price was a large
factor in the IEC cashing in at least part of
its option, “the main turning point” was
lower-than-expected electricity demand
in Israel.
She told Interfax that, although the IEC
felt it had a good deal with the option –
linked to the United States consumer price
index (CPI), which has been consistently
falling since 2012 – it was not overly happy
with the price relative to the sums paid
by rivals.
“They are not that pleased with the
price, because there are other [independent
power producers: IPPs] in the market
who bought gas linked to the electricity
generation price,” she said. “Since the
electricity price fell these IPPs now pay a
lower price than the IEC [as well as] others,
such as the oil refineries, who bought gas
linked at the oil price.”
Price too low
However, the IEC price, which was set at
$5.04/MMBtu for this latest tranche and
30% linked to the US CPI, is still relatively
low compared with the $5.70/MMBtu
the company is paying for the bulk of its
supplies. “Their belief was that, ‘yes, we
need some more gas and so let’s buy this
cheap tranche that is available to us’,”
said Cohen.”
Cover story
Furthermore, electricity demand is
shrinking in Israel and is up to 10% lower
than forecast by the Ministry of Energy and
Water, and the IEC is losing market share
to smaller IPPs.
Cohen said wanting to stall competition
might be “in the back of IEC’s mind”, as
contracting for the gas means the Tamar
partners must keep it available if the
IEC wants it, even if they do not end up
taking it.
The agreement between the IEC and
the Tamar partners means that, from 2020,
the IEC’s take-or-pay quantity will rise to
3 billion cubic metres per year and the
maximum total quantity to be supplied
up until 2028 will be around 87 bcm –
compared with 99 bcm if the option had
been exercised fully and 83.5 bcm if it had
not been exercised at all.
The final date by which the IEC had to
notify the Tamar partners whether it would
exercise the option was 15 April, and Israeli
newspaper Globes reported the company
hoped the deadline would be delayed again
until more suppliers could enter the market.
When the Antitrust Authority’s draft
proposal did not address any of the IEC’s
competition concerns and finally fell through,
the Ministry of Finance and the authority
asked the Tamar partners to allow the IEC to
exercise only part of the option.
Contact the author at: editorial.news@interfax.co.uk
Today on
interfaxenergy.com
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pricing and abuse of market power in
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interfaxenergy.com Natural Gas Daily | 23 April 2015 | 2
4. More from interfaxenergy.com/gasdaily/fsu
THE estimated $27 billion Yamal LNG
project in Russia’s Arctic has committed the
majority of its output to customers in Asia,
but it needs a further $10-15 billion to bring
the plant to completion.
Of the project’s 16.5 mtpa of expected
capacity, 14.78 mtpa – nearly 90% – is
already committed under long-term supply
contracts, a strong sign that the project
is viable.
Total and China National Petroleum Corp.
(CNPC) each have 20% stakes in Yamal
LNG, with operator Novatek holding the
remaining 60%. However, after Novatek
was added to the European and American
sanctions list last year and oil prices
declined, the three partners have found it
difficult to secure the financing they need
to complete the project.
With $10 billion already locked in,
Novatek received RUB 150 billion (nearly
$3 billion) from Russia’s National Wealth
Fund in January. But the remainder has yet
to be secured.
“A wide range of export credit agencies
from Europe and the Asia Pacific region,
and a large pool of banks, are involved in
talks on financing this project,” Novatek’s
Chief Executive Leonid Mikhelson told
reporters this month. “We assess the current
status of the talks as very positive, and we
can confirm that binding documents will
be signed during the first half of this year,
Yamal sells 90% of LNG, but billions still needed
so project financing can be opened in the
middle of the year.”
“Financing by shareholders will amount
to about 35% of investment, perhaps a
little more. We plan to cover the rest with
external financing. Economic estimates
show that, even in the worst-case scenario,
the project is capable of bringing its
shareholders profit when it reaches full
capacity,” he added.
Positive potential
Total’s Chief Executive Patrick Pouyanné
reiterated Novatek’s optimism, saying that
even amid volatile oil and gas prices the
resource potential of Yamal LNG ranks
the project as one of the world’s best. He
also noted that the gas is easy to extract
and that the project’s economics will be
attractive with an oil price of around
$60 per barrel.
Another option for securing financing
may be for Novatek to sell around 9% of
its stake in Yamal. The Russian company
first suggested it might sell a share in 2013,
and Mikhelson confirmed while in Sabetta
on the Yamal peninsula this month that
Novatek plans to complete negotiations
to reduce its 60% stake by the middle of
this year. He gave no further indications
to reporters.
Interest in joining the project could come
from buyers in Asia – such as India, where
importers already have contracts for Russian
LNG – or from Total or CNPC.
The 14.78 mtpa of sold capacity
includes the supply to Yamal’s stakeholders
– 2.38 mtpa for Novatek Gas & Power; up to
4 mtpa for Total Gas & Power; and 3 mtpa
for CNPC, at a price indexed to the Japanese
Crude Cocktail. The majority of these
volumes are destined for Asian markets.
Gazprom Marketing and Trading
Singapore also signed a 20-year long-term
agreement for 2.9 mtpa for delivery to Asia
in January, “primarily to India with the LNG
price indexed to crude oil”, it said.
Spain’s Gas Natural Fenosa has agreed
to buy another 2.5 mtpa from Yamal, which
represents nearly 10% of Spain’s total
annual gas consumption.
Delivery routes
The difficulty with all Arctic energy projects
is transporting products to customers in
extreme weather conditions. The Novatek-
led joint venture plans to deliver LNG from
Yamal in Arctic-class carriers to customers
in Europe year-round.
During the Arctic summer, which lasts
about six months a year, Yamal will ship
LNG east to customers via the Northern Sea
Route (NSR), according to Yamal LNG Chief
Executive Yevgeny Kot. Shipments to Asia
through the NSR will be much faster than
through the Suez Canal, saving about 25
days for shipments to Japan, while delivery
times to China will depend on the location
of the terminal.
During winter, the LNG carriers will head
west to the Zeebrugge terminal in Belgium,
where the LNG will be unloaded from
the Arctic-class carriers and loaded onto
conventional LNG carriers for delivery to
the Asia Pacific market via the Suez Canal.
Yamal LNG subsidiary Yamal Trade signed a
20-year contract with Fluxys LNG in March
to ship up to 8 mtpa of LNG to Zeebrugge,
which has been a major source of LNG
reloads since 2008.
The Arctic South-Tambeyskoye field is
estimated to hold 491 billion cubic metres
of proven gas reserves and 14 mt of proven
liquid hydrocarbon reserves. The launch
of the first of the three planned 5.5 mtpa
liquefaction trains is planned for 2017, with
the 16.5 mtpa project expected to reach
capacity in 2021.
Contact the editor at: therese.robinson@interfax.co.uk
Work taking place at the Yamal LNG site. The stakeholders are optimistic about its prospects. (Novatek)
Although the majority of Yamal LNG’s capacity is committed, a further
$10-15 billion is needed to complete the Arctic project. Russia Correspondent
Svetlana Savateeva reports from Moscow with Therese Robinson in London.
FSU (excluding the Baltic states)
interfaxenergy.com Natural Gas Daily | 23 April 2015 | 4
5. Local content under Moz’s new petroleum law
Mozambique does not have a specific local content law, but its vision for how local content principles should be applied in its
nascent oil and gas industry is reflected in its updated petroleum law, published in August 2014. The legislation requires the
training and employment of local citizens, that preference be granted to local services and goods, and that local citizens and
companies have the opportunity to hold equity stakes in Mozambican oil and gas projects wherever possible. Investors are waiting
for the new regulations – now expected in June – to provide clarity on exactly how these principles will be enforced in practice.
Here are some of the key points they will watch for.
Watch point: It is unclear if companies will have to list their
share capital or part of it on the Mozambican stock exchange,
or if it is just a matter of joining with the central securities
register, which is managed by the stock exchange.
Watch point: It is likely that, given the size of Mozambique’s
reserves, the domestic market will not have the capacity to
consume this 25% quota. The assumption is that this gas will
be used to help national industrialisation and development
of downstream industries, such as GTL and petrochemical
products, which will then be exported. It is also possible the
national oil company ENH, which will be responsible for selling
on the quota, will be able to sell the gas directly into regional
markets – for example South Africa, which is suffering a major
power shortage.
Watch point: It is not clear whether ENH will take the lead in
marketing LNG or just in domestic gas sales. The national oil
company, which has little experience of global LNG markets,
will likely have to partner with other project developers when
marketing internationally.
Watch point: As the term ‘national interest’ is not defined
in the law, investors will need further clarity. The ‘specific
legislation’ that holders will need to act in accordiance with has
yet to be approved.
Watch point: As the term ‘commercial interest’ is not defined
under the petroleum law, investors will look for further clarity
on this. The volumes referred to here are likely to be over
and above the 25% domestic market obligation, and will not
necessarily be managed by ENH (unlike the domestic market
obligation). It is also unlikely suppliers will need to drop
existing supply obligations to meet local industry demand, as
the government will not want to jeopardise the commerciality
of developments. However, further clarity is needed on this.
Article 13: Promotion of national
entrepreneurship
1) The government shall create mechanisms and outline
the conditions for the involvement of the national
entrepreneurship in oil and gas enterprises.
2) The oil and gas companies must be registered on the
Mozambique stock exchange.
Article 35: Oil and gas for internal consumption
1) The government shall guarantee that a quota of no less than
25% of the oil and gas in Mozambique is dedicated to the
national market.
2) The government rules the acquisition, price and other
matters related to the use of the oil and gas quota
mentioned above.
Article 36: Marketing and commercialisation
1) The government shall guarantee that ENH takes the lead in
the marketing and sale of petroleum products
Article 40: Obligations for the conduction of
petroleum operations
h) When the national interest so requires, holders of a
reconnaissance exploration and production, infrastructure,
construction and operation, and oil or gas pipeline system
right shall give preference to the government in the
acquisition of petroleum produced in the contract area, in
accordance with the specific legislation.
Article 49: Development of industrial activity
1) The petroleum resources shall be used, whenever required,
as raw material for the processing industry.
2) The state may request the petroleum product at negotiable
prices for use in the local industry, whenever the country’s
commercial interests demand it.
Article 12: The workforce
2) Exploration companies need to ensure employment
and technical training of Mozambicans, as well as their
participation in the management of petroleum operations.
Leigh Elston in Maputo
Sources: Presentation given by Telmo Ferreira, Founding
partner of Couto, Graça Associados in Maputo
21 April; Mozambique’s Petroleum Law No.
21/2014, of 18 August
Mozambique petroleum law
interfaxenergy.com Natural Gas Daily | 23 April 2015 | 5
6. Malaysian LNG exports dip below 2 mt
Malaysia’s monthly LNG exports dropped
below 2 mt for the first time since mid-2014
in February, as deliveries to both Taiwan and
South Korea fell, according to data provided
to Interfax by the country’s Department of
Statistics. Exports amounted to 1.99 mt in
February, down by 21.86% month on month
and 5.84% year on year.
The decline was the result of reduced
deliveries to Malaysia’s second and third
largest customers. Taiwan’s imports fell
by 49.58% year on year to 122,760 tons,
while South Korea’s dropped by 33.49%
to 170,432 tons.
While deliveries to Taiwan over the first
two months of 2015 were still higher than
they were in 2014, exports to South Korea
have continued their downward trend from
2014 – declining by 37.45% year on year
in January and February to 645,307 tons.
South Korea’s LNG demand has weakened
over the past year because of oversupply in
its storage sites and the planned addition
of 3 GW of nuclear capacity later this year.
Malaysia’s exports to China, meanwhile,
increased by 1.95% year on year to
192,844 tons, and deliveries to Japan
remained unchanged at 1.51 mt. Japanese
buyers are already Malaysia’s largest LNG
importers, having taken 15.5 mt over the
last two years.
Toho Gas recently signed up for additional
volumes, signing a heads of agreement with
Petronas LNG in March that will provide the
Japanese utility with seven-to-nine cargoes
per year from the state-run exporter’s
global portfolio over 10 years starting in
April 2017, under a contract that links the
price to both crude oil and the Henry Hub.
Prices for Malaysian LNG imports were
generally lower in February, as spot prices
continued to decline and the country’s
long-term oil-indexed contracts began to
reflect the recent plunge in crude oil prices.
Excluding China, prices for Malaysia’s
largest East Asian customers have fallen
by $2-3/MMBtu compared with the same
period last year.
Robert Sullivan in Hong Kong
Average Malaysian LNG export prices
$/MMBtu
Source: Malaysian Department of Statistics, InterfaxChina Japan South Korea Taiwan
4
6
8
10
12
14
16
18
20
Jan
2015
Oct
2014
Jul
2014
Apr
2014
Jan
2014
Oct
2013
Jul
2013
Apr
2013
Jan
2013
Oct
2012
Jul
2012
Malaysian LNG exports, year-on-year change, Feb 2015 vs Feb 2014
Source: Malaysian Department of Statistics, Interfax
-50%
-40%
-30%
-20%
-10%
0%
10%
TaiwanSouth KoreaJapanChina
1.95%
0.14%
-33.49%
-49.58%
Malaysian LNG exports, year-on-year comparison
mt
Source: Malaysian Department
of Statistics, Interfax
0.0
0.5
1.0
1.5
2.0
2.5
DecNovOctSepAugJulJunMayAprMarFebJan
China, 2015 Japan, 2015 South Korea, 2015 Taiwan, 2015
China, 2014 Japan, 2014 South Korea, 2014 Taiwan, 2014
China, 2013 Japan, 2013 South Korea, 2013 Taiwan, 2013
Malaysian Number Crunch
interfaxenergy.com Natural Gas Daily | 23 April 2015 | 6
7. More from interfaxenergy.com/gasdaily/asiapacific
SANY Group has joined the growing ranks
of companies from outside the energy sector
diversifying into the oil and gas industry in
search of new business. Interfax spoke to Miao
Xionghui, a vice president at the company,
about the expansion.
Interfax: How do you see China’s gas market
growing in the future?
Miao Xionghui: Oil prices have plummeted
since last year, but China’s gas prices didn’t
follow suit. It’s an issue that can be traced
back to the energy structure.
However, I expect more reforms to the
gas sector to come out soon, including the
deregulation of the residential gas sector.
More measures will be taken and a mixed
ownership model will appear in more gas
companies, so there will be more participation
by private companies.
There is also the growing focus on the need
for a cleaner energy mix. Burning coal or oil
affects air quality greatly, while gas is relatively
cleaner. So I believe China’s gas market will
witness great growth in the future, as will
demand for gas-related equipment.
Interfax: When will China push through
market reforms for residential gas?
MX: It’s hard to predict exactly when, but
I think there will be some moves in the
Chinese machinery group targets energy sector
direction of the market later this year. China
will encourage private companies to join
the reform, shifting away from the current
NOC monopoly.
Interfax: China saw meagre gas consumption
growth in 2014. How did that affect demand
for equipment?
MX: There was a big impact last year.
Equipment demand shrank overall, and there
was considerably less demand for equipment
related to unconventional gas development.
That has continued this year, with some
companies booking a lot fewer orders in the
first quarter. But I don’t think the situation was
caused by market fundamentals – it was more
to do with policy. Gas became less competitive
because tariffs didn’t track the decline in oil
prices. Sany wasn’t greatly affected as we’re
a newcomer and don’t have a large market
share right now.
Interfax: What’s the outlook for 2015?
MX: This year will be hard, as oil prices won’t
rebound to the levels before last year’s slump.
Manufacturers, especially small-to-midsized
companies, face a tough year. But for others,
this could be an opportunity. Low oil prices
will put off some companies from entering the
market and push some existing players out.
It is a good time for technology upgrades to
wait for another boom period as the market
will grow in the long run.
Interfax: Sany made its name in construction
machinery. What lay behind the decision to
diversify into energy equipment?
MX: We felt Sany needed to do more than
just manufacture construction machinery
if it wanted to be a multinational company.
And the energy sector is a big market, much
bigger than construction machinery. Energy is
also a focus of the Chinese leadership’s reform
efforts, and Sany would like to be part of the
process. My personal view is that the energy
sector is quite closed with little competition
in the market, so energy equipment is not
particularly advanced as a result. We hope
we can help speed up the upgrading of oil
and gas equipment and technology, for the
benefit of the energy sector. That will also help
Sany to grow.
Interfax: What equipment is China unable
to manufacture and can only import? What
advantages do domestic manufacturers such
as Sany have over foreign firms?
MX: For fracking, we’re still reliant on
importing equipment like high-horsepower
engines and gearboxes. I think we have
several advantages. We are more familiar
with Chinese geological conditions and
client demands, and we are quick to respond
in customer service for things like repairs
and parts replacement. We’ve simplified
equipment so it’s more manageable – such as
replacing one big engine with six smaller but
standardised ones, which shortens lead times
and means clients can do repairs themselves.
Currently, we have four or five fracking units
working in the Changqing oilfield.
Interfax: China is developing unconventional
oil and gas on a large scale. How does
equipment need to be tailored for China?
MX: Taking shale gas as an example, the
geology is not ideal as many blocks, such
as Fuling and Weiyuan, are in mountainous
terrain. Also, drilling sites are usually small,
so you can only have a limited number of
vehicles on site. So frack trucks need to be
able to climb steep hills, adjust to varying
road conditions and be multifunctional.
Contact the author at: juliet.lee@interfax.cn
Sany fracking trucks at the Changqing oilfield. The company is moving into the energy sector. (Sany Group)
Miao Xionghui, vice president of research and development at Sany Group,
talks to Li Xin about why the Chinese heavy machinery maker is confident
about its expansion into the energy industry.
China
interfaxenergy.com Natural Gas Daily | 23 April 2015 | 7
8. ARGENTINA has successfully cut its gas
imports over the past few months, and
Buenos Aires is hoping that increased nuclear
power production will further reduce the
need for expensive LNG cargoes. However,
the sector is blighted by the poor availability
of plants, uneconomic production costs and a
lack of transparency.
Argentina’s nuclear power capacity is
1.63 GW, which is about 5.1% of the country’s
installed capacity of around 32 GW. There
are three plants in Argentina: Atucha I
(335 MW) and Atucha II (692 MW) in Buenos
Aires province, and Embalse (600 MW) in the
central province of Córdoba.
Atucha II came online in June 2014 and
reached 100% of its rated power in February.
President Cristina Fernández de Kirchner
claimed that Atucha II would save the country
$400 million per year in fuel imports with oil
prices at $54 per barrel.
“If it were to increase, then savings would
be even higher,” she said.
But Buenos Aires-based analysts are
sceptical. “The cost of nuclear power is far
from affordable for Argentina, and availability
for dispatch is close to 70%, which is poor,”
Daniel Gerold, of Buenos Aires-based GG
Energy Consultants, told Interfax.
“Argentina won’t get anywhere near those
[$400 million] import savings because the
nuclear fleet is too unreliable,” said another
consultant, who wanted to remain anonymous
because of political sensitivities.
Nuclear power not the answer for Argentina
Establishing the availability of the nuclear
fleet is difficult because the Argentine
government does not publish aggregated
annual historical data for the electricity sector.
However, nuclear plant availability has been
patchy in recent months, according to local
press. Embalse has been offline since August
2014 as authorities seek to extend its service
life. Atucha I went offline on 7 March for three
months of scheduled maintenance. Atucha
II is generating at 80-100% of its installed
capacity, but was offline between 29 October
and 16 November 2014. Work on Atucha II
began in 1981, but was continually delayed
by funding difficulties. None of the bodies
overseeing Argentina’s nuclear sector
returned calls seeking comment.
The nuclear option
It is clear that a reliable nuclear fleet and
baseload power supply would reduce demand
for LNG imports. Wholesale power market
administrator CAMMESA estimated before the
startup of Atucha II that nuclear power could
account for 4-9% of Argentine electricity
production, depending on availability. Thermal
generation forms 50-60% of the mix, with
hydroelectricity accounting for 30-40%.
Just under one third of gas consumed
in Argentina is used for power generation,
according to data from the United States
Energy Information Administration. Industry
and the residential sector account for 28% and
24% of the country’s gas demand respectively.
“Argentina does not have an alternative to
LNG right now in terms of power generation.
But the startup of Atucha II may be able to
meet some of the country’s power demand,”
Mauricio Roitman, a consultant at Buenos
Aires-based energy advisory Montamat
Asociados, told Interfax last year.
Argentina’s nuclear ambitions rely on
Russian technology and Chinese cash. De
Kirchner met her Russian counterpart Vladimir
Putin this week to follow up on deals for
civilian nuclear energy projects signed in July
2014. Details of Argentina’s agreement with
Russia have not been released, although it is
likely to be related to the third Atucha reactor,
which will cost $2.4 billion. De Kirchner also
signed agreements with Beijing in September
2014 over the construction of Atucha III using
Chinese funds.
Jorge Lapeña, Argentina’s former energy
secretary, said on 20 February that the
Argentine government should not sign further
deals with Beijing until they were able to
economically justify the projects.
Power producers are struggling to remain
profitable in Argentina, with electricity spot
prices capped at ARS 120/MWh ($13.52/
MWh) according to the variable cost of
production with gas from available generating
units, even if they are not using gas.
CAMMESA designates additional costs for
liquid fuel consumption outside the specified
market price as a temporary dispatch
surcharge. Generators argue the price does
not reflect their costs and have called for tariff
increases to help them remain in business.
Temporary dispatch surcharges were around
ARS 1,800-1,900/MWh on 22 April, according
to CAMMESA.
Lapeña leads a group of former Argentine
energy secretaries who have regularly called
for greater transparency in the power sector.
This includes open letters to ENRE, the
country’s electricity regulator, demanding the
publication of updated data. ENRE’s most
recent annual report was published in 2012.
Atucha II’s startup also had a political
flavour, Lapeña said: “The timing [18
February] appears chosen to counter the
effects of the march of silence in tribute to
Prosecutor [Alberto] Nisman [a lawyer who
died in suspicious circumstances earlier this
year].” Lapeña also accused de Kirchner of
misrepresenting the origins of Argentina’s
nuclear power plants for populist purposes.
Contact the editor at: chris.noon@interfax.co.uk
Argentina's power industry
Source: CAMMESA, Interfax estimates
Gas
13.2 GW
Diesel
1.3 GW
Nuclear
1.6 GW
Hydropower
11.1 GW
Coal
4.4 GW
Solar/wind
0.1 GW
Total installed capacity
31.7 GW
More from interfaxenergy.com/gasdaily/latinamerica
Buenos Aires has claimed that increased nuclear power production will
slash LNG imports, but experts are sceptical about the secretive sector.
Latin America Editor Chris Noon reports from Buenos Aires.
Latin America
interfaxenergy.com Natural Gas Daily | 23 April 2015 | 8
![© 2015 Interfax LtdInterfax Information Services Group interfaxenergy.com
Natural gas insight, analysis and intelligence
Volume 5 Issue 77
Thursday, 23 April 2015
Interfax Information Services Group
interfaxenergy.com
THE decision by Israel’s dominant electricity
company to exercise only part of its
purchase option for gas from the Tamar
field should benefit other projects in the
region, industry experts say.
Israel Electric Corp. (IEC) told Tamar
owners Noble Energy and Delek Group
last week it would buy just $1.5 billion of
additional Tamar volumes from 2020, much
less than the $6 billion it had optioned.
The decision was said to have been
triggered by doubts about the Israeli
Antitrust Authority’s proposal to break up
the ownership duopoly over Israel’s gas
fields, as well as the need for an anchor
customer to fund development of the
estimated 538 billion cubic metre Leviathan
field. Price was also said to have been an
issue. The IEC could not be reached
for comment.
Amit Mor, chief executive of Eco
Energy Financial & Strategic Consulting,
called the IEC’s decision “practical” because
the company needs more suppliers
to ensure energy security, and given
the potential for delay if the Antitrust
Authority’s demand to break up the
ownership of the fields is not dealt with
in the next few months.
“The reality now [is] there are two
additional major fields that need to be
developed [requiring a large customer],”
Mor told Interfax. “It [the reduced option] is
a necessity… so additional suppliers would
have a market.”
As well as the IEC’s need for more
suppliers, the owners of the Leviathan field
need a large – if not an anchor – customer
to get development underway.
Nati Birenboim, chief executive of
consultancy Tamuz Group, said the Israeli
company wanted to keep its options open
to be able to buy from new sources – such
as Leviathan or the two smaller Karish and
Tanin fields – at potentially cheaper prices
in future.
Leviathan looming
As the country’s main power provider as
well as the dominant Tamar customer
(taking up to 40% of all sales from that
field), Birenboim said the IEC would also
need to be a key buyer of Leviathan gas to
make development of that field viable.
“It was easy to finance Tamar because
the whole market was waiting for it,” he
told Interfax. “That’s not the situation with
Leviathan. The market today is crowded
so it’s good for Leviathan to have these
customers too.”
Israel’s offshore gas fields in the Mediterranean.
IEC hedges its bets with
‘practical’ Tamar decision
Yamal sells 90% of LNG,
but billions still needed
Breaking around the world
Local content under
Moz’s new petroleum law
Malaysian LNG exports
dip below 2 mt
Chinese machinery group
targets energy sector
Nuclear power not the
answer for Argentina
LNG
Interview
Supply & Demand
4
3
5
6
7
8
Israel
West
Bank
Jordan
Syria
Mediterranean
Sea
Cyprus
Block 12
David
Rachel
Hanna
Eran
Tamar
Amit
Dalit
Noa
Mari
A
B
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A C
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![Independent energy consultant Gina
Cohen said that, although price was a large
factor in the IEC cashing in at least part of
its option, “the main turning point” was
lower-than-expected electricity demand
in Israel.
She told Interfax that, although the IEC
felt it had a good deal with the option –
linked to the United States consumer price
index (CPI), which has been consistently
falling since 2012 – it was not overly happy
with the price relative to the sums paid
by rivals.
“They are not that pleased with the
price, because there are other [independent
power producers: IPPs] in the market
who bought gas linked to the electricity
generation price,” she said. “Since the
electricity price fell these IPPs now pay a
lower price than the IEC [as well as] others,
such as the oil refineries, who bought gas
linked at the oil price.”
Price too low
However, the IEC price, which was set at
$5.04/MMBtu for this latest tranche and
30% linked to the US CPI, is still relatively
low compared with the $5.70/MMBtu
the company is paying for the bulk of its
supplies. “Their belief was that, ‘yes, we
need some more gas and so let’s buy this
cheap tranche that is available to us’,”
said Cohen.”
Cover story
Furthermore, electricity demand is
shrinking in Israel and is up to 10% lower
than forecast by the Ministry of Energy and
Water, and the IEC is losing market share
to smaller IPPs.
Cohen said wanting to stall competition
might be “in the back of IEC’s mind”, as
contracting for the gas means the Tamar
partners must keep it available if the
IEC wants it, even if they do not end up
taking it.
The agreement between the IEC and
the Tamar partners means that, from 2020,
the IEC’s take-or-pay quantity will rise to
3 billion cubic metres per year and the
maximum total quantity to be supplied
up until 2028 will be around 87 bcm –
compared with 99 bcm if the option had
been exercised fully and 83.5 bcm if it had
not been exercised at all.
The final date by which the IEC had to
notify the Tamar partners whether it would
exercise the option was 15 April, and Israeli
newspaper Globes reported the company
hoped the deadline would be delayed again
until more suppliers could enter the market.
When the Antitrust Authority’s draft
proposal did not address any of the IEC’s
competition concerns and finally fell through,
the Ministry of Finance and the authority
asked the Tamar partners to allow the IEC to
exercise only part of the option.
Contact the author at: editorial.news@interfax.co.uk
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