Argus LNG Daily

Argus LNG Daily
Daily LNG prices, news and analysis
Issue 14-17 Friday 24 January 2014
Market Commentary
prICES
Asian winter prices set for March peak
Northeast Asian spot LNG prices rose significantly today amid
growing expectations that winter prices will peak for March
deliveries.
“Buyers had expected winter prices to be highest for
February, so I am very surprised that March is now looking to
be higher,” a Japanese buyer said.
Sellers are now indicatively offering March cargoes at
above $20/mn Btu as supply remains tight. But there is a
wide bid-offer spread of around $1.50/mn Btu for March,
with buying ideas up to the high-$18s/mn Btu.
Around three Japanese utilities have possibly bought four
March cargoes in the low- to mid-$19/mn Btu range, but this
could not be confirmed. One mid-March cargo was possibly
sold at $20/mn Btu, although the deal may not be representative of where March could trade. “The cargo buyer possibly had specific requirements on delivery timing, cargo size
or vessel size, and because cargoes are limited in supply, the
buyer may have had to pay a premium,” a trader said.
Market participants see the low- to mid-$19/mn Btu range
as more a realistic transaction level for March cargoes.
Japanese utilities continue to drive spot procurement
in northeast Asia. They had sought around 3-4 February
cargoes, but were unable to secure any because of limited
spot availability. February procurement is becoming too
prompt for deliveries, leading buyers to eye alternative fuels
for power generation needs that month and also consider
deferring spot purchases to March. “Some Japanese utili-
Argus Asia-Pacific des spot LNG
Delivery
Northeast Asia (ANEA™)
China
India
$/mn Btu
Bid
Offer Midpoint
1H Mar
18.95
20.05
19.500
+0.425
2H Mar
18.75
19.85
19.300
+0.550
1H Apr
17.85
18.95
18.400
+0.675
1H Mar
18.90
20.10
19.500
+0.425
2H Mar
18.65
19.95
19.300
+0.550
1H Apr
17.70
19.10
18.400
+0.675
1H Mar
17.10
18.30
17.700
-0.250
2H Mar
16.80
18.10
17.450
-0.250
1H Apr
16.05
17.15
16.600
-0.150
Argus European des spot LNG
Delivery
NW Europe
±
$/mn Btu
Bid
Offer Midpoint
±
2H Feb
10.90
15.85
13.375
1H Mar
10.70
15.65
13.175
+0.125
Iberian peninsula
2H Feb
14.95
16.10
15.525
+0.050
1H Mar
14.70
15.95
15.325
+0.050
Italy
2H Feb
11.40
15.95
13.675
+0.125
1H Mar
11.15
15.75
13.450
+0.125
2H Feb
11.30
15.95
13.625
0.000
1H Mar
11.20
15.75
13.475
+0.050
2H Feb
14.70
16.00
15.350
0.000
1H Mar
14.50
15.80
15.150
+0.050
Greece
Turkey
Argus fob spot LNG
$/mn Btu
Loading
Bid
Iberian peninsula reload
2H Feb
15.50
1H Mar
West Africa (AWAF™)
2H Feb
Trinidad and Tobago
+0.125
Offer Midpoint
±
16.40
15.950
+0.100
15.25
16.25
15.750
+0.150
15.45
16.40
15.925
+0.050
1H Mar
15.30
16.25
15.775
+0.050
2H Feb
15.40
16.30
15.850
+0.050
1H Mar
15.20
16.15
15.675
+0.050
Latest price snapshot
$/mn Btu
European prices
Asia des prices
NW Europe des (2H Feb): 13.375
Northeast Asia (ANEA) (1H Mar): 19.500
Iberian peninsula des (2H Feb): 15.525
Southeast Asia (ASEA) (1H Mar): 18.41
Iberian peninsula reload (2H Feb): 15.950
Italy des (2H Feb): 13.675
Greece des (2H Feb): 13.625
Turkey des (2H Feb): 15.350
Middle East fob
China des (1H Mar): 19.500
To Europe: 12.83
India des (1H Mar): 17.700
To Asia: 17.12
Trinidad and Tobago fob
(2H Feb): 15.850
West Africa (AWAF) price
(2H Feb): 15.925
Australia fob
17.59
Copyright © 2014 Argus Media Ltd
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
ties cannot completely switch their fuel requirements from
gas to alternative fuels. They can switch some but not all,
so there will still be March spot LNG demand,” a northeast
Asian buyer said.
March prices had been expected at a significant backwardation of up to $1/mn Btu to February, but have remained high on tight supplies. Demand has been stable
amid a mild winter, with only Japanese utilities buying
while major South Korean and Chinese importers stay quiet.
And weather is set to stay mild, with Japan's meteorological agency today predicting average weather countrywide
in the month ahead. “The high prices are supply driven, so
once cargoes emerge prices could fall quickly, possibly from
second-half March or April onwards,” another northeast
Asian buyer said.
Spot supplies could come via reload cargoes from European terminals, although increased gas withdrawals from
European storage could reduce the number of such cargoes
scheduled. Gas withdrawals in Europe increased in the seven
days to 22 January because of colder weather across the
continent. The region's weekly stockdraw totalled 1.5bn m3,
up slightly from 1.48bn m3 for the week to 16 January. Inventories slipped to 49.2bn m³, down from 52.5bn m³ a year
earlier but comfortably above 42.6bn m³ in 2011.
Availability could also be boosted as the 5.2mn t/yr Angola LNG plant is expected to load a cargo by end-January,
although this could be delayed to February.
“Angola should seek to load the cargo by end of this
month, if it wants to sell in time to capitalise on current
high prices,” a trader said. The price impact will depend on
Angolan production. There could be significant price downside if the plant loads around 3-4 cargoes a month, especially if South Korea and China continue to have no demand.
But the market impact is likely to be minimal if it loads just
one cargo a month, as it did before the shutdown.
The backwardation between second- and first-half March
has narrowed to 20¢/mn Btu on tight supplies, with secondhalf March trades expected in the high-$18 to low-$19/mn
Btu range. April discussions have yet to start, but a backwardation of around $1/mn Btu is tentatively expected.
The ANEA price, the Argus assessment for northeast
Asia des, is up by 42.5¢mn Btu at $19.50/mn Btu for first-half
March, up by 55¢/mn Btu at $19.30/mn Btu for second-half
March, and up by 67.5¢/mn Btu at $18.40/mn Btu for first-half
April deliveries. China's des prices are assessed at parity to
the ANEA.
Argus spot LNG freight
$/day
Price
$/mn Btu
Delivery
Price
±
April
17.15
+0.80
May
15.65
+0.05
June
15.45
0.00
Benchmark price snapshot
Market
Delivery
Price
Natural gas
$/mn Btu
Nymex
Feb
5.07
NBP
Feb
10.97
Zeebrugge
Feb
10.71
Peg Nord
Feb
10.84
PSV
Feb
11.46
WTI
Mar
96.31
Brent
Mar
107.71
JCC*
Oct
113.48
Crude
$/bl
*Japanese Cocktail Crude
Key netbacks
$/mn Btu
Southeast Asia (ASEA)
Delivery
Price
±
1H Mar
18.41
+0.33
2H Mar
18.19
+0.41
1H Apr
17.27
+0.58
Australia fob
Prompt
17.59
+0.27
Middle East fob (Asia-Pacific bound)
Prompt
17.12
+0.27
Middle East fob (Europe-bound)
Prompt
12.83
+0.18
Argus Victoria Index (AVX) - Friday 24 Jan 2014
Delivery
Units
Bid
Offer
Midpoint
±
February
A$/GJ
3.98
4.37
4.175
-0.095
February
$/mn Btu
3.68
4.03
3.853
-0.115
The AVX index, the first month-ahead index for Australia’s east coast Victorian
natural gas market, is assessed each Friday and reproduced through the week. The
date shown is the date of the assessment. The index will also appear in the east
coast Australian markets page each Friday
A$/GJ
Argus Victoria index (AVX)
4.5
4.0
3.5
±
Freight west of Suez
70,000
-18,000
Freight east of Suez
75,000
-5,000
Copyright © 2014 Argus Media Ltd
Argus Northeast Asia swaps
3.0
30 Aug 13
Page 2 of 15
18 Oct 13
6 Dec 13
24 Jan 14
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
Indian spot prices slipped, as participants took a price
reference from three second-half February and first-half
March delivery cargoes sold at the mid- to high-$17s/mn Btu
to state-owned importers.
Petronet bought two cargoes – one for second-half February and another for first-half March – at slightly above the
mid-$17/mn Btu level, while Gail bought a first-half March
cargo at $17.50/mn Btu. The cargoes bought by Petronet
possibly came from the Middle East, because of shipping
proximity and supply availability.
India's des prices are assessed down by 25¢/mn Btu at
$17.70/mn Btu for first-half March and $17.45/mn Btu for
second-half March deliveries. First-half April is assessed
down by 15¢/mn Btu at $16.60/mn Btu.
Atlantic fob firms on Asian demand
Fob prices in the Atlantic basin rose again based on bullish
price movement in northeast Asia, where delivered prices
have been climbing due to very tight supply in both basins.
With very few cargoes available for loading over the
next few weeks, offers are up because the cost of diverting already-committed cargoes would need to be high. One
mid-March cargo may have been sold at $20/mn Btu to a
Japanese utility.
Atlantic basin traders said that any sign of demand was
contributing to volatile prices due to tight supply. At the
beginning of the week, prices were softening due to low
demand combined with few available cargoes. But Asian
demand has picked up over the last few days, while cargoes
have remained scarce, leading to upward pressure on prices.
Even possible supply from Angola’s 5.2mn t/yr Soyo
export terminal and Norway’s 4.2mn t/yr Snohvit export
terminal is unlikely to have any great impact on current
market tightness. There is considerable scepticism among
traders as to whether Angola LNG will produce more than
one cargo ahead of the shoulder season, when des and fob
prices are anticipated to soften. The first cargo since the
commissioning shutdown is expected to be tendered in
early February. Snohvit generally produces a maximum
of two spot cargoes a month if the plant is operating at
capacity.
Enel’s tender for six fob or des cargoes from Nigeria’s
22mn t/yr Bonny plant also ended today. One trader
involved in bidding said there had been a lot of interest in
the tender and prices this year could be higher than last
year. In 2013, Enel sold the Nigerian cargoes at roughly
13.5pc slope to the Brent crude price, he said.
Meanwhile, no demand for spot cargoes has been
heard in Europe. Low LNG demand means any re-exports
loaded next month from terminals in Spain, Belgium or the
Netherlands could go to northeast Asia. Argentina may also
retender for spot cargoes. In its most recent tender, staterun YPF awarded two cargoes, leaving three unfulfilled.
Shipping rates were also expected to fall further this
year. One ship broker said there were 23 vessels available
in January and seven in February. Traders said that rates
could easily fall to the $50,000/day region.
Generally, lower freight rates means high fob prices
because traders can save on shipping costs and bid higher
for cargoes.
Global supply highlights
Supply
Loading period
1 cargo from Angola LNG
Late Jan
16-Jan
16-Jan
1 or 2 cargoes from Snohvit
2H Feb
15-Jan
15-Jan Depending on stable production
3 full Spanish re-exports scheduled
Jan
28-Nov
14-Jan One sold, two cancelled
6 Nigerian cargoes offered by Enel
Gas year 2014
10-Jan
10-Jan Tender deadline 24 Jan. Offered des or fob.
2 full Spanish re-exports scheduled
Feb
27-Dec
1 re-export from Gate, Netherlands
Jan
5-Nov
6-Jan
2 cargoes from Snohvit
Jan
2-Dec
3-Jan Depending on stable production
Strip of three cargoes from Bonny,
Nigeria
April-Sept 2014 (flexible)
17-Dec
18-Dec
Cargoes offered from Balhaf, Yemen
Jan
12-Dec
12-Dec
Cargoes offered from Qalhat, Oman
Jan
12-Dec
12-Dec
Possibly 1 cargo from Lumut, Brunei
Q1 2014
22-Nov
22-Nov
Copyright © 2014 Argus Media Ltd
First reported
Page 3 of 15
Last updated Comments
Plant ramping up, tender expected after
vessel loads
8-Jan Sold
Offered by capacity holders. Sold and more
unlikely
Tendered by an offtaker with plenty of loading slots. Tender now closed.
Cargoes depend on upstream output, will be
offered to term customers first
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
Global demand highlights
Demand
Delivery period
Unspecified number of cargoes from
Petronet
2H Mar
23-Jan
23-Jan
1-2 cargoes for North America
Feb
22-Jan
22-Jan
North American importers enquiring about
spot cargoes
5 cargoes from YPF, Argentina
Feb-Mar
13-Jan
21-Jan
Two cargoes awarded for Bahia Blanca,
March delivery
1 cargo by PetroChina
Mar
21-Jan
21-Jan
1 cargo by PTT
2H Feb
7-Nov
17-Jan
3-4 cargoes from Japanese utilities
2H Feb
2-Dec
16-Jan Some cargoes may be deferred to Mar
1 cargo by GSPC
Jan/Feb
18-Oct
10-Jan
Around 6-7 cargoes from Japanese utilities
Mar
8-Jan
8-Jan
1 cargo by Botas
Feb
13-Nov
8-Jan
7-8 cargoes by Gail
by May 2014
30-Oct
17-Dec
Gail Singapore seeking about 1 cargo per
month until May 2014. 1 Nov, 1 Dec bought
1 cargo by IOC
Late Feb/early Mar
22-Oct
17-Dec
Initial tender for Nov cargo withdrawn,
retendered for Q1 cargo
Two YPF tenders for 120 and 27 cargoes
2014 and 2015
26-Sep
21-Nov
Cargoes awarded to BP, Gazprom, Statoil,
GNF, Petrobras. Rest unfulfilled.
Northeast Asia (Anea) LNG first-half month
19.7
19.6
19.5
19.4
19.3
19.2
19.1
19.0
18.9
18.8
18.7
18.6
11 Dec 13
$/mn Btu
Last updated Comments
Tender cancelled due to high price. Previously bought 3 cargoes for Jan-Mar delivery
Delivery shifted from Jan/Feb to Mar due to
high prices.
10 spot cargoes bought - might need one
more for Feb delivery
Argus Turkey and Greece LNG des
16.0
des Turkey
S/mn Btu
des Greece
15.5
15.0
14.5
14.0
13.5
26 Dec 13
10 Jan 14
ANEA™ front half month
Nymex WTI front month
24 Jan 14
S/mn Btu
JCC, Brent, WTI vs LNG
21
First reported
13.0
10 Dec 13
24 Dec 13
10 Jan 14
24 Jan 14
$/mn Btu
West Africa (AWAF) LNG fob
16.5
JCC
Ice Brent front month
20
19
16.0
18
17
16
15
24 Jul 13
24 Sep 13
Copyright © 2014 Argus Media Ltd
20 Nov 13
23 Jan 14
15.5
10 Dec 13
Page 4 of 15
24 Dec 13
10 Jan 14
24 Jan 14
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
Global shipping highlights
Vessel
Capacity m³ From
To
Loading
Arrival Notes
Iberica Knutsen
138,000 Bonny, Nigeria
Dabhol, India
29 Dec
Berge Arzew
138,000 Arzew, Algeria
Tobata, Japan
28 Dec
26 Jan Spot cargo
Bilbao Knutsen
138,000 Point Fortin, Trinidad
Canaport, Canada
17 Jan
26 Jan Send out high due to cold
LNG Libra
126,400 Point Fortin, Trinidad
Escobar, Argentina
15 Jan
Grace Barleria
149,700 Arzew, Algeria
Malacca, Malaysia
8 Jan
25 Jan
27 Jan Gas Natural Fenosa cargo for YPF
28 Jan Spot cargo
LNG Port Harcourt
122,000 Bonny, Nigeria
Altamira, Mexico
12 Jan
28 Jan
Marib Spirit
165,500 Balhaf, Yemen
Ningbo, China
14 Jan
29 Jan
Soyo
160,000 Bonny, Nigeria
Montoir, France
20 Jan
29 Jan
LNG Taurus
126,300 Ras Laffan, Qatar
Tobata, Japan
12 Jan
30 Jan
Methania
131,200 Bonny, Nigeria
Sagunto, Spain
21 Jan
31 Jan
Yenisei River
155,000 Sagunto, Spain
South Korea
Arctic Discoverer
140,000 Snohvit, Norway
South America
18 Jan
Lobito
160,000 Snohvit, Norway
Futtsu, Japan
26 Dec
2 Feb Angola LNG project vessel
Grace Dahlia
177,000 Ras Laffan, Qatar
Zeebrugge, Belgium
16 Jan
3 Feb
5 Jan
31 Jan Re-export
1 Feb Possibily Argentina
GDF Suez Point Fortin
154,200 Idku, Egypt
Tianjin, China
16 Jan
Wilpride
156,000 Gate, Netherlands
Futtsu, Japan
6 Jan
4 Feb
Seri Angkasa
145,000 Bonny, Nigeria
South Korea
14 Jan
9 Feb
Castillo de Santisteban
173,700 P. Melchorita, Peru
Oita, Japan
20 Jan
10 Feb
5 Feb Re-export
Lena River
155,000 Bonny, Nigeria
Bahia Blanca, Argentina
22 Jan
11 Feb Gazprom cargo for YPF
Cadiz Knutsen
138,800 Snohvit, Norway
Futtsu, Japan
11 Jan
13 Feb Diverted from Barcelona
LNG Enugu
145,000 Bonny, Nigeria
Joetsu, Japan
17 Jan
14 Feb Spot cargo
Seri Begawan
152,300 Arzew, Algeria
Futtsu, Japan
14 Jan
14 Feb
Madrid Spirit
138,000 Point Fortin, Trinidad
Manzanillo, Mexico
22 Jan
16 Feb
LNG Borno
149,600 Bonny, Nigeria
Ohgishima, Nigeria
18 Jan
18 Feb
$/t
Middle East bunker fuel - Fujairah
380cst
660
475
180cst
450
650
425
640
630
400
620
375
610
350
600
325
590
17 Oct 13
19 Nov 13
20 Dec 13
24 Jan 14
$/t
European bunker fuel - Rotterdam
675
No. of ships
Global LNG tanker fleet projections
180cst
380cst
1.5% 180cst
300
2012
700
2015
2016
380cst Sing
180cst SKorea
$/t
180cst Sing
380cst SKorea
675
625
650
600
625
575
600
550
16 Oct 13
2014
Asia Pacific bunker fuel
1.5% 380cst
650
2013
18 Nov 13
Copyright © 2014 Argus Media Ltd
19 Dec 13
24 Jan 14
575
17 Oct 13
Page 5 of 15
19 Nov 13
20 Dec 13
24 Jan 14
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
News
Petrobras Bahia LNG plant still not operational
Brazilian state-controlled Petrobras said that its third
regasification terminal is not yet operational, and has not
given a start-up date for the facility.
The company announcement contradicts a Brazilian energy ministry report on 13 January, which said the terminal
began operations in December.
Petrobras originally said the LNG terminal would begin
activities in September, and has not given an explanation for
the delay. The 126,300m³ LNG Capricorn loaded a re-export
cargo from Portugal's Sines plant at the end of December,
which arrived at Salvador earlier this week. The vessel has
been offshore Brazil since then, according to ship tracking data. The ministry could not be reached for comment
regarding the terminal.
The new LNG facility will bring Petrobras' regasification
capacity to 41mn m³/d. The company already has two operating terminals — one located in Guanabara in Rio de Janeiro
state with 20mn m³/d of capacity and another 7mn m³/d
facility in Pecem, Ceara state.
Brazil imports LNG to power thermoelectric plants,
which are used to complement hydroelectric generation during dry periods. In 2013, Brazil imported record volumes of
$/mn Btu
Argus Iberian peninsula des
16.0
15.5
LNG because of drought conditions which reduced reservoir
levels.
Although initial weather forecasts called for normal to
above-average rainfall this summer season, precipitation
levels so far have been disappointing, with the government
forced to maintain thermoelectric capacity. Hydroelectric
reservoirs in the southeast-centrewest subsystem declined
this month, reaching 41.29pc of maximum capacity on 23
January from 43.18pc at the end of December.
The country also experienced a heatwave this summer,
which pushed electricity demand to record levels in recent
days. Temperatures in Sao Paulo, the country's most populous state, are at their highest levels in over 50 years.
Strong hydro weighs on Spanish gas demand
Spanish gas system operator Enagas has forecast a 0.8pc
year-on-year decline in gas demand in February to 1.14
TWh/d, from 1.15 TWh/d in the previous year. But the outlook depends on normal levels of hydroelectric generation
— and with reservoir levels well above the five-year average
— January's hydroelectric generation has been strong, with
more rain and wind forecast heading into February.
Enagas has forecast power-sector gas demand of 176
GW/d, assuming normal levels of hydro generation, in line
January levels.
But hydroelectric generation so far this month has been
strong, averaging 122 GWh/d — the highest since 2011, and
up from a five-year January average of 106.8 GWh/d. In
January 2013, hydroelectric output averaged just 89 GWh/d.
Latest estimated LNG distribution by destination
15.0
m³
Asia-Pacific
15,133,590
Europe
2,941,674
North America
14.5
736,500
South America
816,300
Upstream
14.0
10 Dec 13
24 Dec 13
10 Jan 14
24 Jan 14
15,662,781
Based on vessels at sea, final destination and estimated arrival time. Upstream
figure includes all major production regions.
Netbacks
$/mn Btu (front half month)
Japan
South
Korea
Taiwan
Iberian
peninsula
Greece
Italy
Turkey
17.16
17.43
13.88
12.40
12.26
14.08
11.53
21.60
2.93
17.90
18.18
12.98
11.51
11.50
13.16
10.78
20.84
2.56
16.20
14.59
12.44
12.56
14.07
12.34
22.90
3.93
India
China
Middle East
16.75
17.22
17.06
Australia
16.04
17.95
17.88
Nigeria
15.11
15.99
15.85
15.93
NW
Europe
Northeast US
US Gulf
Norway
14.71
15.26
15.10
15.20
15.46
14.87
12.62
12.74
14.27
13.02
23.24
3.92
Algeria
15.47
16.04
15.89
15.99
16.25
15.33
13.40
13.42
15.08
13.02
23.23
3.95
Trinidad and Tobago
14.19
15.16
15.02
15.11
15.38
14.59
12.40
12.51
14.04
12.41
23.84
4.68
Russia
15.44
18.45
18.58
18.59
18.43
12.38
10.97
10.94
12.60
10.23
20.28
2.19
Copyright © 2014 Argus Media Ltd
Page 6 of 15
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
And gas-fired plants have generated just 49 GWh/d, the
lowest for the time of year since January 2003 — just nine
months after Spain's first combine-cycle gas turbine (CCGT)
was brought on line.
In February 2013, hydroelectric generation was significantly stronger — at 116 GWh/d — than the same period one
year earlier at 41 GWh/d. Together, wind generation and
hydroelectric output accounted for 34.1pc of Spanish power
generation that month, while gas-fired generation's share
slipped to just 9pc. Gas-fired plants generated 72 GWh/d,
and pulled 157 GWh/d from the gas transmission system.
Enagas expects conventional demand next month to be
around 969 GWh/d based on usual weather conditions, compared with 992 GWh/d in February last year, amid low temperatures and a cold snap at the end of the month. Today,
longer-range forecasts for Spain pointed to temperatures
broadly in line with the long-term average for February.
Annual gas demand could reach 345TWh in 2014, according to Enagas' latest demand outlook, up by 3.5pc
from 333.4TWh consumed last year. That scenario includes
conventional demand rising to 283TWh from 277TWh in 2013
— and, assuming coal remains cheaper than gas, power-sector gas demand increasing to 62.5TWh from 56.8TWh. This
would be equivalent to an increase of 9.5pc.
The latest outlook is unchanged from the revised demand outlook published in October 2013, when consumption
was expected to be 335TWh, of which conventional demand would be 279TWh and power-sector gas demand was
expected to be 56TWh. In the event, conventional demand
was slightly lower than anticipated, but power-sector gas
demand was boosted in December by low wind output and
two nuclear power stations off line at the end of the year.
But October's year-end outlook was revised down
significantly from Enagas's year-ahead outlook for 2013.
Earlier last year, Enagas had foreseen 2014 demand reaching
NBP
Delivery
$/mn Btu
Bid
Ask
±
Day-ahead
10.87
10.89
+0.184
Feb
10.95
10.99
+0.073
+0.019
Mar
10.76
10.80
Apr
10.61
10.64
-0.014
2Q14
10.43
10.45
-0.006
3Q14
10.36
10.39
+0.005
4Q14
11.14
11.17
-0.014
Summer 2014
10.39
10.41
+0.001
Winter 2014-15
11.38
11.40
-0.028
Summer 2015
10.23
10.27
-0.037
2015
10.75
10.78
-0.030
2016
10.48
10.52
-0.058
2017
10.21
10.25
-0.027
Copyright © 2014 Argus Media Ltd
350TWh, with conventional demand of 282TWh in 2013 rising
to 286TWh in 2014, and power-sector gas demand reaching
58TWh in 2013, rising to 65TWh in 2014.
But in fact, both conventional and power-sector gas demand fell short of the earlier forecast despite unusually cold
weather in the first part last year. Demand in 2013 was 8pc
lower than in 2012, with power-sector gas demand accounting for most of the fall. Power-sector gas demand in 2013 fell
on the year by 33pc, and totalled just 30pc of the 186.5TWh
used for power generation in 2008. Overall power output fell,
while wind and hydrogenation took a larger share of that output. Wind generation overtook nuclear generation to become
the biggest contributor to Spanish power output in 2013.
Argentina peso devaluation could impact LNG
The sharp devaluation of Argentina's currency has sharply
increased the country's LNG bill. Argentina has become increasingly reliant on LNG, amid surging demand and plunging
production.
The Argentinian peso yesterday experienced its largest
devaluation in more than 12 years, when it declined around
12pc day on day — with the official US dollar exchange rate
closing at Ps8, quickening a trend that had been seen for
months. The peso has devalued 22pc so far this month and
33pc since mid-November, when President Cristina Fernandez
de Kirchner appointed economy minister Axel Kicillof as part
of a broad cabinet reshuffle.
Over the last few months, Argentina's state-run oil company YPF tendered for around 100 cargoes to be delivered in
2014-2015 worth billions of dollars. Most of the volumes were
awarded to BP, Spain's Gas Natural Fenosa, and Russian statecontrolled Gazprom, with some going to Norwegian statecontrolled Statoil, Brazilian state-controlled Petrobras, and
Shell. The bulk of the winning bids were for around $15-17/mn
Btu, which is equivalent to roughly $45mn-51mn per standardsized cargo.
The winning bid likely did not price in the risk of selling
LNG to Argentina, according to one trader involved with the
YPF tender. In previous years, Argentina has failed to pay for
its LNG on time, which means the country usually pays more
for LNG than its regional neighbours.
The last time the currency declined so much in one day
was amid the country's economic collapse, which led to a record debt default. But the key difference now is that Argentina did not import energy at the time, a trend that has been
accentuating in recent years.
Energy imports rose by 36pc in January-November 2013
to $8.09bn, compared with the same period in 2012, according to the latest figures from the energy secretariat. LNG
imports accounted for 43pc of total energy imports during
that period.
In the past, Argentina's central bank has intervened in
Page 7 of 15
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
the foreign exchange market, as Kirchner's administration
followed a policy of a managed exchange rate that failed to
keep up with an inflation rate — pegged at 20pc over many
years, according to some analysts. But the monetary authority has taken a waiting stance, allowing larger fluctuations in
the local currency, despite the central bank's international
reserves having dropped to seven-year lows.
The government instituted stringent controls on access to the currency in July 2012, amid soaring demand for
dollars, and banned the purchase of foreign currency for
savings. That led to a surge in a black market for the dollar
to trade at around 12 pesos. That is a gap the government is
seeking to close.
The peso's depreciation is expected to continue as the
government aims to lift some of the restrictions on dollar
sales, it said today. The move would allow the currency to
be purchased for savings.
Canaport sends more gas to New England
Canada's Canaport LNG import terminal yesterday was
scheduled to send 480mn cf/d (14mn m³/d) of gas to the
US northeast — its fourth consecutive day of notable flow
resulting from a weather-related surge in New England gas
prices.
Spot prices for gas delivered yesterday at Algonquin
Citygates averaged more than $75/mmBtu, up by about $21/
mmBtu from the previous session. Prices at Tennessee Gas
pipeline zone 6, which also serves New England, averaged
more than $65/mmBtu, up by about $12/mmBtu. Those
prices were the highest for each location since Argus started
publishing the indexes in late 2009.
The 1.2 Bcf/d Canaport terminal, located in St John, New
Brunswick, is typically underused because of the US shale
gas boom, though it can send significant volumes to the US
via the Maritimes & Northeast pipeline during peak-demand
periods.
Canaport's sendout to the US so far this month has averaged 214mn cf/d. That is more than double the December
average of 103mn cf/d and reflects a significant increase in
heating demand.
Temperatures in Boston, Massachusetts, tomorrow probably will be in a range of 14°-18°F (-10° to -8°C), compared
with a historical average range of 22°-36°F for the day,
according to AccuWeather. Today's temperature range in
Boston likely will be 6°-20°F.
The Elba Island LNG import terminal in Georgia yesterday
was scheduled to flow 103mn cf/d into the regional pipeline
grid. It would be the second time this year that the terminal
would have significant sendout amid high gas prices at Transco gas pipeline zone 5, which extends from the GeorgiaSouth Carolina border to the Virginia-Maryland border.
Gas delivered yesterday to Transco zone 5 averaged more
Copyright © 2014 Argus Media Ltd
than $86/mmBtu, down by about $29/mmBtu from the previous session, as colder-than-normal weather boosted heating demand. The 1.8 Bcf/d terminal, which is significantly
underused, flowed 372mn cf/d on 7 January and 296mn cf/d
on 6 January. Gas delivered to Transco zone 5 on 7 January
averaged about $70/mmBtu, up by more than $59/mmBtu
from the previous session.
Sendout from Elba Island dropped significantly after bidirectional flow started on the 189-mile (304km) Elba Express
pipeline in April 2013. That allowed Elba Island customer BG
to serve some contractual commitments in Georgia with less
expensive pipeline gas from Transco rather than regasified
LNG from Elba Island.
Sabine Pass to provide LNG for ship bunkering
Some excess capacity at Cheniere Energy's Sabine Pass LNG
export terminal in Louisiana will provide LNG bunker fuel for
vessels along the US Gulf coast, an industry executive said.
Cheniere has reached an agreement to provide supplies
from Sabine Pass to LNG Central, which plans to form an
LNG vessel and storage network throughout the Gulf coast
and some interior locations, LNG Central chief executive
Keith Meyer said at Zeus Intelligence's World LNG Fuels conference in Houston.
LNG Central is first focusing on using barges to provide
LNG bunker fuel along the coast, Meyer said. The project is
slated to come on line as soon as Sabine Pass starts production, in late 2015 or early 2016. Houston-based Cheniere
will be an investor in LNG Central and the venture is looking
for additional partners, said Meyer, a former executive at
Cheniere.
LNG Central is looking to also supply LNG for other
high-horsepower markets that are considering using LNG
instead of diesel fuel, including exploration and production,
railroads, mining, trucking and remote power generation.
The North American shale gas boom has made natural gas
significantly cheaper than diesel in the continent, in energy
equivalents, and savings from switching could also be realized in other parts of the world.
Large investments in distribution infrastructure and new
engines are needed to allow such fuel-switching, so the
amount of switching so far has been limited.
The North American marine industry has another incentive to switch to LNG, as regulations will be implemented
next year that will significantly restrict sulfur emissions from
marine vessels operating within 200 nautical miles (230
miles, or 370km) of US or Canadian coastlines.
LNG Central plans to initially use LNG bunkering barges
with capacities of 1,000-3,000m³, equivalent to 21mn-62mn
cf (594,000-1.75mn m³) of gas, Meyer told Argus.
The company would eventually use shuttle vessels, with
capacities of 20,000-25,000m³, to transport to storage
Page 8 of 15
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
facilities it would install along the Gulf Coast. Sabine Pass,
located near the Louisiana-Texas border, is ideally suited to
serve the entire Gulf coast, he added.
Meyer declined to discuss what LNG Central will pay for
its LNG, or what it will charge for LNG bunker fuel. Cheniere
is charging liquefaction fees ranging from $2.25-$3/mmBtu,
depending on when contracts were signed. In addition,
customers that want LNG would pay 115pc of the Nymex gas
futures contract settlement price for the month in which a
cargo is scheduled.
Cheniere has signed long-term tolling deals totaling 16mn
t/yr, equivalent to 2.2 Bcf/d (62mn m³/d) of gas, from the
first four liquefaction trains it is building. Cheniere has said
those trains could produce up to 18.6mn t/yr under normal
weather patterns and as much as 20mn t/yr under coolerthan-normal temperatures.
That would leave 2.6mn-4mn of extra supply available
to sell to a number of potential buyers, including end-users
around the world and LNG Central.
Nova Scotia gas production continues to grow
Nova Scotia offshore gas supply continued to increase this
month after hitting a four-year high in December, helping
to alleviate supply constraints in the far northeast US in a
colder-than-normal winter.
Production from Encana's Deep Panuke and ExxonMobil's
Sable Offshore Energy fields reaches customers in the northeast US via the Maritimes & Northeast pipeline. Receipts
into the US segment of Maritimes at Baileyville, Maine, this
month averaged 256mn cf/d (7mn m³/d), up from an average
of 144mn cf/d in December. That volume excludes sendout
from the Canaport LNG import terminal in New Brunswick.
Higher production from Deep Panuke is driving the
increase. Output at that offshore field averaged 207mn cf/d
in December, according to the Canada-Nova Scotia Offshore
Petroleum Board. Maintenance at Deep Panuke cut November 2013 output to an average of 67mn cf/d.
Deep Panuke started producing in mid-August. The design capacity of that field is 300mn cf/d.
December output from Sable averaged 132mn cf/d, down
by 2.3pc from the previous month and 11pc lower than in
December 2012.
Combined output from Deep Panuke and Sable last
month averaged 339mn cf/d. Nova Scotia offshore output,
from Sable alone, last was at that level in January 2010.
Sendout from Canaport also increased this month from
Copyright © 2014 Argus Media Ltd
December 2013. Net receipts into the US segment of Maritimes this month more than doubled to 459mn cf/d from an
average of 220mn cf/d last month.
Spot natural gas prices in New England remain among
the highest in North America. But higher supply entering the
northern part of that region helped to temper price gains
relative to New York City markets.
Cash gas prices at Algonquin Citygates during a cold snap
this week reached a high of about $75/mmBtu while Transco
zone 6 New York prices shot to about $121/mmBtu. New England prices during the unusually cold weather on 7 January
trailed New York prices by about $20/mmBtu.
Gazprom to increase gas exports to Ukraine
Russian state-controlled Gazprom plans to sell more gas
to Ukrainian state-owned Naftogaz after both companies
agreed on a price reduction.
Gazprom hopes to sell 35bn-40bn m³ to the Ukrainian
firm this year, according to Gazprom foreign affairs deputychief Viktor Valov. This would be close to the minimum
take-or-pay level stipulated in the 10-year agreement signed
in January 2009.
But Gazprom has no plans to sell any gas to private-sector firm Ostchem, Valov said. Ostchem received a discounted
price of $269/'000m³ on the 7bn m³ it received from Russia
last year to inject into storage. This is close to the Ukrainian
group's annual consumption.
Ukraine plans to increase its imports from Russia after
Gazprom agreed to reduce the price Naftogaz pays, to
$268.50/'000m³ from about $400/'000m³. Ukraine's aggregate imports would be about 30bn-33bn m³ this year, energy
minister Eduard Stavitsky said in December following the
discount annoucenment. Ukraine's imports of Russian gas fell
to 26bn m³ in 2012, compared with 33bn m³ in 2013.
Ukraine had reduced its imports from Russia in recent
years during a dispute with Gazprom, and started buying gas
from western Europe via reverse flows through Poland and
Hungary.
But reverse flows halted on 1 January, when the discount
Naftogaz received from Gazprom came into force. Hub prices have been considerably above $268.50/'000m³, offering
little incentive for Ukraine to import from western Europe.
Gazprom also expects Naftogaz to ask to postpone a
deadline to pay for its gas, Valov said. The Ukrainian firm
owes $2.7bn, which is due by the end of the month, Gazprom said.
Page 9 of 15
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
Argus Victoria Index (AVX)
Australia weekly - market commentary
Milder weather caps prices
Victorian wholesale gas prices for month-ahead deliveries softened on ample supplies and expectations of lower
temperatures further out in February. But forecasts of warm
weather in the short term are helping to keep prices steady
within a low A$4/GJ ($3.67/mn Btu) range.
A heat wave that hit most of southeast Australia in firsthalf January has subsided, easing gas demand for power generation to drive air-conditioning needs. But extremely hot
weather is expected in the region again in the coming week,
with maximum temperatures tipped to reach just below
40°C for 27-28 January, according to Australia's meteorology
bureau.
“A little bit of heat is expected next week. Monday is a
public holiday in Australia so gas demand and prices should
be stable, but we could see some volatility Tuesday,” a
retailer said.
Maximum temperature levels from late January to early
February are expected to stay high at above 30°C for Victoria and South Australia states, although they should start
dipping from second-half February. The bureau of meteorology is forecasting average temperatures for most of southeast Australia from February to April, with just a higher
probability of warmer than average weather at 60pc near
the coasts of Victoria and News South Wales.
“Further out, we could see spurts of warm weather that
could support or lift gas demand for power generation,”
another retailer said.
The warmer than expected weather in southeast Australia during January has significantly increased gas use for
power generation. Studies by independent Australian energy
consultancy EnergyQuest showed that without ready access
to supplies fuelling gas-fired power generation, peak power
demand for the period could not have been met. Gas supplied 46pc of the increased power generation in Victoria
from 13-17 January, when the heat wave was at its most
intense, compared with 28pc for hydropower and 26pc for
coal. In South Australia, gas accounted for 91pc of increased
power generation for the period, compared with just 2pc
for coal and around 6pc for renewables, EnergyQuest said.
Total power generation from 13-17 January increased 19pc
in Victoria and 32pc in South Australia, compared with the
previous summer, the firm said.
Prices in the Adelaide short-term trading market (STTM)
rose to over A$6/GJ last week on increased withdrawals for
power generation, although Victorian prices largely remained stable.
Victorian power plants also sought coal to meet increased power demand, helping to ease gas requirements.
Coal is the base-load fuel for power generation in Victoria,
compared with gas in South Australia.
Copyright © 2013 Argus Media Ltd
Delivery
Units
Bid
Offer
Midpoint
±
February
A$/GJ
3.98
4.37
4.175
-0.095
February
$/mn Btu
3.68
4.03
3.853
-0.115
AEMO weekly average Victoria 6am price
Delivery
Units
Price
±
Prompt
A$/GJ
4.02
+0.06
Prompt
$/mn Btu
3.73
+0.01
Units
Price
±
A$/GJ
17.81
+0.25
$/mn Btu
16.53
+0.01
A$/GJ
19.21
-0.01
$/mn Btu
17.83
-0.24
LNG netbacks weekly average
Gladstone oil-linked LNG
Gladstone spot LNG
Victoria prices also kept steady as there were sufficient
supplies on term contracts to meet increased withdrawals
in the Victorian Declared Transmission System (DTS). “In
the absence of a heating load, retailers have spare capacity
in their contracts to provide for increased gas demand,” a
buyer said. This means increases in gas withdrawals from the
DTS are met by adequate injections into the system, reducing the need to buy additional gas.
Victorian demand and supply is balanced, with bids for
injections and withdrawals stable. Market participants have
been taking a conservative approach to bids, with 60pc of
the injection bid at below $10/GJ, a trader said.
The AVX, the index for gas traded on the Victorian DTS,
is assessed at A$4.175/GJ ($3.853/mn Btu), down by A9.5¢/GJ
from 17 January. Bids are at around A$3.98/GJ, while selling
indications are around A$4.37/GJ. The Victorian DTS covers
the Longford, BassGas and Port Campbell gas processing
plants, the Vic Hub, Sea Gas and Culcairn injection points
and the Iona and Dandenong storage facilities.
News
Analysis — Australia gas market waits on Arrow
The decision by Australian coal-bed methane (CBM) producer Arrow Energy to review staffing levels in an effort to
reduce costs has called into question the future development plans for the firm's fields.
Arrow, a joint venture between Shell and Chinese
state-controlled energy firm PetroChina, produces CBM for
Queensland-based users including state-owned power generator Stanwell, utility Alinta and fertilizer group Incitec
Pivot. The CBM is largely supplied by the Moranbah gas
project in the northern Bowen basin that is jointly owned
by Arrow and Australian utility AGL Energy.
Page 10 of 15
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
Arrow has also spent about four year developing a twotrain 9mn t/yr LNG project at Queensland's Gladstone port.
But Shell and PetroChina have been cautious about pushing
ahead with Arrow LNG because of the high cost of onshore
projects in Australia and concerns about the price outlook
following the surge in North American shale gas output.
The companies have already spent more than A$4bn to
acquire the Arrow Energy assets, paying A$3.5bn — equivalent to $3.2bn at the time — for Arrow Energy in 2010. The
transaction followed Shell's purchase of 30pc of Arrow's
Queensland CBM reserves and 10pc of its then international
CBM reserves for a total of $454mn. Shell and PetroChina
then bought Australian CBM group Bow Energy for A$535mn
in 2011, adding the Bow business to Arrow.
Most of Arrow's proven and probable (2P) CBM reserves
are in Queensland's Surat basin, where Arrow had 2P reserves of 7,009PJ (182.23bn m3) at the end of 2012, and a
further 2,422PJ in the Bowen basin, according to a report
by energy and engineering consultants Sinclair Knight Merz.
This puts Arrow's 2P reserves below the level of two of
the three LNG projects being built at Gladstone. The 9mn
t/yr Australia Pacific LNG (APLNG) venture had 2P reserves
of 13,748PJ at the end of 2012, according to the report.
The 8.5mn t/yr Queensland Curtis LNG (QCLNG) project
operated by UK-listed BG had 2P reserves of 8,732PJ in
the Surat basin. And the 7.8mn t/yr Gladstone LNG (GLNG)
project operated by Australian independent Santos had 2P
reserves of 5,784PJ in the Surat and Bowen basins.
Arrow's breakeven gas production costs are A$4.50/GJ
($4.15/mn Btu), higher than for each of the other CBM-toLNG projects at A$3.50/GJ, the report estimates.
The Arrow partners have been in co-operation talks
with the developers of the three LNG projects. At least
two of these projects will probably need to acquire additional gas in the medium term to keep the LNG plants
operating at full capacity and meet their sales contracts.
Arrow has said it “will continue to assess development
options, including collaboration opportunities, as it looks
to develop significant gas reserves.”
Arrow's 2P reserves equate to more than 10 years of
current gas demand in eastern Australia, making it unlikely
that such vast CBM reserves could be soaked up by domestic customers. A tie-up with one of the existing CBM-toLNG developers at Gladstone seems a more likely option
for Shell and PetroChina as they look to achieve a return on
their investment.
Australia's federal government in December granted environmental planning approval to Arrow LNG for the staged
construction of up to four trains with a total capacity of
18mn t/yr. But the prospect of a standalone CBM-to-LNG
project may be challenging given that the other three LNG
project developers at Gladstone have experienced cost
blowouts totalling $9.6bn.
Copyright © 2013 Argus Media Ltd
Gas output falls at Santos Cooper basin
Gas production from Australian independent Santos' Cooper
basin operations in South Australia and Queensland fell in
2013, with its share of output having fallen by more than
half in the last eight years.
Gas production fell to 61PJ (1.59bn m3) in 2013 from
66.6PJ in 2012. Production was less than half the 124.7PJ
produced in 2005 and almost a third of the 165.7PJ that
Santos produced in 2001.
Santos has been producing gas from the Cooper basin for
50 years. The operations were its largest assets for much
of its early years. Santos' gas production in the basin made
it the second largest gas supplier to the eastern Australia
market, behind Bass Strait joint venture between ExxonMobil and UK-Australian resources firm BHP Billiton.
BHP Billiton's share of gas production from the Bass Strait
fell to 56.93bn ft3 (1.59bn m3) in July-December 2013 from
66.73bn ft3 a year earlier. This implies that total production
from the Bass Strait venture was 3.18bn m3 in the period
compared with 3.74bn m3 a year earlier.
BHP Billiton said the fall in gas output from the Bass
Strait reflected lower seasonal demand. The peak demand
period is the winter months of June-August.
The upgrade of the Bass Strait Longford gas conditioning
plant to process about 400mn ft3/d is 25pc complete and on
track to start production in 2016. BHP Billiton jointly owns
the project with ExxonMobil, with its share of the budget at
$520mn.
Eastern Australian gas demand is about 740PJ/yr. This
implies the Bass Strait joint venture supplies about a third of
east coast gas demand, with Santos' Cooper accounting for
just over 8pc.
But Santos' total gas supply accounts for about 13.5pc
of eastern Australian demand. Santos produces coal-bed
methane at Denison, Scotia and Spring Gully in Queensland,
at the Fairview field that is part of its 7.8mn t/yr Gladstone
LNG project in Queensland, and from the Otway basin offshore Victoria.
A$/GJ
Argus Victoria index (AVX)
4.5
4.0
3.5
3.0
30 Aug 13
Page 11 of 15
18 Oct 13
6 Dec 13
24 Jan 14
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
Australia data
Daily eastern Australian pipeline flow rates
TJ
Capacity
TJ/d
Pipelines/injection points
17 Jan
18 Jan
19 Jan
20 Jan
21 Jan
22 Jan
23 Jan
Victoria
Lang Lang (BassGas) Gas Plant
70.0
44.0
48.0
47.0
45.0
48.0
47.0
47.0
1145.0
697.0
472.0
395.0
533.0
337.5
559.0
583.0
Orbost Gas Plant
100.0
28.0
28.0
28.0
28.0
28.0
28.0
28.0
Iona Underground Gas Storage (Port Campbell)
570.0
75.4
29.9
23.0
37.9
35.1
48.0
53.2
Longford Gas Plant
81.0
55.0
40.0
45.0
53.0
50.0
50.0
50.0
Otway Gas Plant (Port Campbell)
Minerva Gas Plant (Port Campbell)
203.0
127.0
163.0
165.0
166.0
164.0
166.0
166.0
Dandenong LNG Storage
158.0
na
na
na
na
na
na
na
NSW-Victoria Interconnect (Culcairn)
120.0
79.0
75.1
69.8
56.6
48.1
64.3
57.5
Longford to Melbourne Pipeline (LMP)
354.7
1030.0
466.6
267.4
250.7
347.8
337.5
351.9
South West Pipeline (SWP)
353.0
-0.5
70.4
65.8
38.2
40.4
46.0
23.5
SEA Gas Pipeline
310.0
221.7
130.6
126.5
136.6
131.7
132.8
173.3
SEA Gas Pipeline (Adelaide zone)
310.0
204.3
124.3
119.8
154.5
124.0
117.8
153.6
Tasmania Gas Pipeline (TGP)
129.0
52.8
53.4
54.9
55.9
59.0
57.0
57.3
Eastern Gas Pipeline (EGP) (Canberra zone)
289.0
2.2
1.3
2.2
2.3
2.3
2.3
2.3
Eastern Gas Pipeline (EGP) (Sydney zone)
289.0
123.5
73.1
70.5
116.9
118.2
115.9
123.2
Eastern Gas Pipeline (EGP)
289.0
243.5
166.1
166.5
228.0
220.7
222.3
235.9
Roma to Brisbane Pipeline (RBP)
233.0
176.9
161.3
156.9
186.4
203.6
204.4
199.7
131.3
Queensland
Queensland Gas Pipeline (QGP) (Roma to Gladstone)
145.0
130.4
133.0
130.6
127.1
128.7
130.9
Carpentaria Pipeline (CGP) (Ballera to Mt Isa)
119.0
93.7
100.9
102.1
101.5
96.7
95.3
97.0
South West Queensland Pipeline (SWQP)
384.0
112.1
105.8
119.7
121.2
153.6
154.6
138.5
South West Queensland Pipeline (SWQP) (Moomba zone)
384.0
60.9
23.0
24.4
28.0
23.0
23.0
18.0
Kenya Gas Plant (Roma)
168.0
121.4
133.9
134.4
121.8
131.7
118.3
111.3
Talinga Gas Plant (Roma)
140.0
97.6
110.5
108.7
105.2
100.5
95.9
100.7
Ballera Gas Plant
150.0
9.8
7.2
0.0
7.8
12.7
4.7
0.0
Moomba Gas Plant
430.0
185.0
142.9
114.4
107.4
93.1
121.3
134.4
Moomba to Sydney Pipeline System (MSP)
289.0
147.2
110.1
101.5
106.9
116.5
120.3
109.6
Moomba to Adelaide Pipeline System (MAP)
241.0
168.1
77.3
75.3
79.9
82.5
80.2
80.8
Moomba to Sydney Pipeline System (Canberra)
289.0
2.8
3.7
3.0
4.0
4.4
4.8
4.6
South Australia
- Australian National Gas Market Bulletin Board
$/mn Btu
Gladstone oil-indexed netback
$/mn Btu
Gladstone spot netback
19
17.0
18
16.5
17
16
16.0
15
15.5
14
15.0
13 Jun 13
28 Aug 13
Copyright © 2013 Argus Media Ltd
11 Nov 13
24 Jan 14
13
13 Jun 13
Page 12 of 15
28 Aug 13
11 Nov 13
24 Jan 14
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
competing fuels in asia and power market indicators
S/mn Btu
Japan: Fuel oil vs LNG
20.0
$/mn Btu
India: Coal vs LNG
ANEA front half month
Fuel oil LSWR V-500 Indonesia inc freight
20
Argus India LNG front half month
Coal del Indonesia - India 4,200 kcal
19.5
15
19.0
18.5
10
18.0
17.5
5
17.0
16.5
29 Oct 13
26 Nov 13
24 Dec 13
$/mn Btu
Japan:Crude vs LNG
21
ANEA™ front half month
Dubai front month inc freight
24 Jan 14
0
29 Oct 13
20
20
24 Dec 13
South Korea: Fuel oil, coal vs LNG
Minas prompt inc freight
20
26 Nov 13
24 Jan 14
$/mn Btu
ANEA™ front half month
Fuel oil HS 180cst South Korea del
Coal del Indonesia - South Korea 5,800 kcal
15
19
10
19
18
5
18
17
29 Oct 13
26 Nov 13
24 Dec 13
$/mn Btu
India: Naptha vs LNG
21
24 Jan 14
0
29 Oct 13
Argus India LNG front half month
Naphtha LR1 Mideast Gulf fob
26
24
19
22
18
20
17
18
16
16
27 Nov 13
Copyright © 2014 Argus Media Ltd
26 Dec 13
24 Jan 14
24 Dec 13
14
29 Oct 13
Page 13 of 15
24 Jan 14
$/mn Btu
India: Fuel oil, gasoil vs LNG
20
15
30 Oct 13
26 Nov 13
Argus LNG India front half month
Fuel oil HS 180cst Mideast Gulf inc freight
Gasoil 0.05% Mideast Gulf inc freight
26 Nov 13
24 Dec 13
24 Jan 14
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
Power market indicators: breakeven gas prices for generation
$/mn Btu
Europe: Front month base load
Spain
13
UK
30
12
$/mn Btu
Latin America
Turkey
Brazil wholesale clearing price
Argentina MEM monthly average
25
11
20
10
15
10
9
5
8
23 Sep 13
7 Oct 13
21 Oct 13
4 Nov 13
0
Dec 10
Jun 11
Dec 11
Jun 12
Dec 12
Jun 13
Monthly lng import volumes
mn m³ LNG
Japan historic receipts
25
20
4
15
3
10
2
5
1
0
May 11
mn m³ LNG
China historic receipts
5
Nov 11
May 12
Nov 12
May 13
Nov 13
mn m³ LNG
South Korea historic receipts
12
0
May 11
Nov 11
May 12
Nov 12
May 13
Nov 13
mn m³ LNG
Spain historic receipts
5
10
4
8
3
6
2
4
1
2
0
May 11
Nov 11
May 12
Copyright © 2014 Argus Media Ltd
Nov 12
May 13
Nov 13
0
Apr 11
Page 14 of 15
Oct 11
Apr 12
Oct 12
Apr 13
Oct 13
Argus LNG Daily
Issue 14-17 Friday 24 January 2014
S/mn Btu
Atlantic benchmarks vs LNG
25
ANEA™ front half month
Nymex gas front month
NBP front month
Ice Brent front month
ANEA™ front half month
22
USGC diesel
21
20
20
15
19
10
18
5
0
30 Jul 13
$/mn Btu
USGC diesel vs LNG
26 Sep 13
20 Nov 13
23 Jan 14
$/bl
Ice brent front month
115
17
24 Oct 13
21 Nov 13
23 Dec 13
23 Jan 14
$/mn Btu
US Nymex
4.5
4.4
4.3
4.2
4.1
110
4.0
3.9
3.8
3.7
3.6
105
10 Dec 13
24 Dec 13
9 Jan 14
23 Jan 14
3.5
Dec-13
1Q 2014
3Q 2015
1Q 2017
3Q 2018
Argus LNG Daily is published by Argus Media Ltd.
Registered office
Argus House, 175 St John St, London, EC1V 4LW
Tel: +44 20 7780 4200 Fax: +44 870 868 4338
email: [email protected]
ISSN: 2046-2301
Copyright notice
Copyright © 2014 Argus Media Ltd. All rights
reserved.
All intellectual property rights in this publication and
the information published herein are the exclusive
property of Argus and/or its licensors and may only
be used under licence from Argus. Without limiting
the foregoing, by reading this publication you agree
that you will not copy or reproduce any part of its
contents (including, but not limited to, single prices
or any other individual items of data) in any form or
for any purpose whatsoever without the prior written
consent of Argus.
Trademark notice
ARGUS, ARGUS MEDIA, the ARGUS logo, ARGUS
LNG Daily, other ARGUS publication titles
and ARGUS index names are trademarks of
Argus Media Ltd. Visit www.argusmedia.com/
trademarks for more information.
Disclaimer
The data and other information published
herein (the “Data”) are provided on an “as
is” basis. Argus makes no warranties, express
or implied, as to the accuracy, adequacy,
timeliness, or completeness of the Data or
fitness for any particular purpose. Argus shall
not be liable for any loss or damage arising
from any party’s reliance on the Data and
disclaims any and all liability related to or
arising out of use of the Data to the full extent
permissible by law.
Natural gas/LNG
illuminating the markets
Publisher
Adrian Binks
Chief operating officer
Neil Bradford
Global compliance officer
Jeffrey Amos
Commercial manager
Jo Loudiadis
Editor in chief
Ian Bourne
Managing editor, Global
Cindy Galvin
Managing editor, Generating
Fuels
Peter Ramsay
Editor
Kwok Wain Wan
Tel: +44 20 7780 4217
[email protected]
Customer support and sales
Technical queries –
[email protected]
All other queries
[email protected]
London, UK
Tel: +44 20 7780 4200
Astana, Kazakhstan
Tel: +7 7172 54 04 60
Beijing, China Tel: + 86 10 6515 6512
Dubai Tel: +971 4434 5112
Moscow, Russia Tel: +7 495 933 7571
Rio de Janeiro, Brazil
Tel: +55 21 3514 1402
Singapore Tel: +65 6496 9966
Tokyo, Japan Tel: +81 3 3561 1805
Argus Media Inc, Houston, US
Tel: +1 713 968 0000
Argus Media Inc, New York, US
Tel: +1 646 376 6130

Download Report