Argus LNG Daily

Argus LNG Daily
Daily LNG prices, news and analysis
Issue 14-150 Friday 1 August 2014
Market Commentary
prICES
Uncertainty over PNG LNG sales in Asia Pacific
Northeast Asian spot prices remained steady today amid
uncertainty over the recent sale of two September cargoes
from the 6.9mn t/yr Papua New Guinea (PNG) LNG plant.
The cargoes for first- and second-half September loading were offered through a tender issued by plant operator
Exxon Mobil last week. Some market participants said the
cargoes were sold in the low- to mid-$10s/mn Btu, while
others said sales were likely to have been done around $11/
mn Btu.
At least two trading firms that bid for the cargoes in
the mid- to high-$10s/mn Btu have had their bids rejected,
suggesting the shipments could have been sold above those
levels. But it is possible that ExxonMobil may have passed
on higher bids from trading and portfolio firms in favour of
slightly lower bids from consumer buyers. Some LNG producers prefer to sell directly to consumers rather than to traders and portfolio players to avoid diluting the market.
It is unclear to which market the PNG LNG cargoes were
sold. Some market participants said both cargoes were
awarded to Japanese utilities, one of which is a term offtaker from PNG LNG. But others said one of the cargoes was
sold to a portfolio supplier. “Current market fundamentals
do not justify a price in the low-$11s/mn Btu. The portfolio
player may be taking a long position and trying to push up
market prices by bidding high,” a trader said.
It is unclear how PNG LNG intends to market the rest of
Argus Asia-Pacific des spot LNG
Delivery
Northeast Asia (ANEA™)
China
India
$/mn Btu
Bid
Offer Midpoint
2H Sep
10.19
10.77
10.480
0.000
1H Oct
10.28
10.93
10.605
-0.015
2H Oct
10.28
10.93
10.605
na
2H Sep
10.20
10.76
10.480
0.000
-0.020
1H Oct
10.29
10.92
10.605
2H Oct
10.29
10.92
10.605
na
2H Sep
10.06
10.69
10.375
0.000
1H Oct
10.11
10.74
10.425
0.000
2H Oct
10.11
10.74
10.425
na
Argus fob spot LNG
$/mn Btu
Loading
Iberian peninsula reload
West Africa (AWAF™)
Trinidad and Tobago
Bid
Offer Midpoint
±
1H Sep
9.30
10.60
9.950
0.000
2H Sep
9.35
10.70
10.025
+0.025
1H Oct
9.45
10.70
10.075
na
1H Sep
9.18
10.03
9.605
+0.055
2H Sep
9.25
10.15
9.700
0.000
1H Oct
9.30
10.15
9.725
na
1H Sep
9.30
10.25
9.775
-0.025
2H Sep
9.40
10.30
9.850
-0.050
1H Oct
9.40
10.35
9.875
na
Argus Atlantic Basin fob spot LNG
Loading
Atlantic Basin
±
$/mn Btu
Bid
Offer Midpoint
±
1H Sep
9.24
10.32
9.778
+0.027
2H Sep
9.30
10.42
9.862
+0.013
1H Oct
9.38
10.42
9.900
na
Latest price snapshot
$/mn Btu
European des prices
Asia des prices
NW Europe des (1H Sep): 8.350
Northeast Asia (ANEA) (2H Sep): 10.480
Iberian peninsula des (1H Sep): 9.500
Southeast Asia (ASEA) (2H Sep): 10.190
Iberian peninsula reload (1H Sep): 9.950
Italy des (1H Sep): 8.750
Greece des (1H Sep): 9.550
Turkey des (1H Sep): 9.650
Middle East fob
China des (2H Sep): 10.480
To Europe: 8.02
India des (2H Sep): 10.375
To Asia: 9.48
Trinidad and Tobago fob
(1H Sep): 9.775
West Africa (AWAF) price
(1H Sep): 9.605
Australia fob
9.80
Copyright © 2014 Argus Media Ltd
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
its September cargoes. A term offtaker said it has the option
of taking cargoes from the plant through tenders or direct
negotiations. PNG LNG is now operating at full capacity,
suggesting some 7-9 cargoes could be produced each month.
Shipping data showed the plant loaded seven cargoes in July.
September supplies are also available from Australia’s
16.3mn t/yr North West Shelf (NWS) LNG plant. NWS issued a
spot tender early this week to sell an unspecified number of
cargoes for loading between end-August and end-November.
There are four 8-10 day loading windows, with two covering September — from 31 August to 9 September and 22-30
September. The tender closes on 4 August and bids are expected to be valid until 8 August. Interest is expected from
consumer buyers and portfolio suppliers, particularly for the
cargoes loading closer to winter. The fourth loading window
for the NWS tender is from 22-30 November, suggesting some
cargoes may be delivered in first-half December to northeast
Asia, in time to meet early winter demand.
But northeast Asian buyers are close to wrapping up
September procurement, amid continued spot availability
for that month. Japanese utilities are not likely to have more
firm September demand, and any purchases would be opportunistic. Buyers from Taiwan and Thailand may seek more
September volumes, although such demand is also likely to
be price-sensitive. State-controlled buyers from South Korea
and possibly China are not expected to have spot needs for
the rest of this year.
October prices are at a slight contango to September,
although that could narrow if market fundamentals remain
soft. October demand is expected to be weak, as it is part
of the autumn shoulder season, while supplies are expected
to stay more than ample.
October spot availability is expected to come from NWS,
PNG LNG, Indonesia’s 22.6mn t/yr Bontang LNG and Russia’s 9.55mn t/yr Sakhalin LNG plants. There are two loading
windows in the NWS tender – 22-30 September and 21-29
October – that could result in cargoes being delivered to
northeast Asia in October. And PNG LNG is also expected to
produce October spot cargoes, albeit at a lower volume if
some term deliveries start. The plant’s term supply agreements with Japan’s Tokyo Electric Power and Osaka Gas,
Taiwan’s state-controlled CPC and China’s state-run Sinopec
are expected to start from end-October or early November.
One of the contracts could start in September, although this
could not be confirmed.
The ANEA price, the Argus assessment for northeast
Asia des, is unchanged at $10.48/mn Btu for second-half
September and down by 1.5¢/mn Btu to $10.605/mn Btu for
first-half October deliveries. It is assessed at $10.605/mn Btu
for second-half October deliveries. China’s des prices are
assessed in line with the ANEA.
Spot prices in India were unchanged today, as state-
Copyright © 2014 Argus Media Ltd
Argus Latin America des spot LNG
$/mn Btu
Delivery
Price
±
Argentina
Prompt
10.54
+0.06
Brazil
Prompt
10.36
+0.06
Chile
Prompt
11.01
+0.08
Mexico Gulf coast
Prompt
10.81
+0.07
Mexico Pacific coast
Prompt
9.94
+0.07
Argus European des spot LNG
$/mn Btu
Delivery
Bid
Offer Midpoint
±
NW Europe
1H Sep
6.90
9.80
8.350
-0.100
2H Sep
6.90
9.80
8.350
na
Iberian peninsula
1H Sep
9.10
9.90
9.500
+0.060
2H Sep
9.30
9.90
9.600
na
Italy
1H Sep
7.60
9.90
8.750
-0.150
2H Sep
7.60
9.90
8.750
na
Greece
1H Sep
9.20
9.90
9.550
-0.200
2H Sep
9.20
9.90
9.550
na
Turkey
1H Sep
9.40
9.90
9.650
-0.100
2H Sep
9.40
9.90
9.650
na
Key netbacks
$/mn Btu
Delivery
Price
±
2H Sep
10.19
0.00
1H Oct
10.30
-0.02
2H Oct
10.30
na
Australia fob
Prompt
9.80
-0.01
Middle East fob (Asia-Pacific bound)
Prompt
9.48
-0.01
Middle East fob (Europe-bound)
Prompt
8.02
+0.09
Southeast Asia (ASEA)
Argus Northeast Asia swaps
$/mn Btu
Delivery
Price
±
Nov
12.63
0.00
Dec
13.63
0.00
Jan
14.95
na
Argus spot LNG freight
$/day
Price
±
Freight west of Suez
47,000
+2,000
Freight east of Suez
46,000
+2,000
Argus Wallumbilla Index (AWX) - Friday 1 Aug 2014
Delivery
Units
Bid
Offer
Midpoint
±
Sep
A$/GJ
1.69
1.95
1.819
-0.281
Sep
$/mn Btu
1.65
1.91
1.780
-0.303
Argus Victoria Index (AVX) - Friday 1 Aug 2014
Delivery
Units
Bid
Offer
Midpoint
±
Sep
A$/GJ
3.84
4.30
4.070
-0.013
Sep
$/mn Btu
3.76
4.21
3.984
-0.067
The AWX and AVX indexes, the first month-ahead indexes for Australia’s east
coast Wallumbilla and Victorian natural gas markets, are assessed each Friday and
reproduced through the week. The date shown is the date of the assessment. The
indexes will also appear in the east coast Australian gas markets page each Friday.
Page 2 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
controlled importers await available receiving capacity and
tank space at the 10mn t/yr Dahej terminal. “Every buyer
has demand for cargoes at current soft prices, but Dahej
inventories remain full. It is unlikely there would be space
until around September,” a state-controlled importer said.
Indicative September bids are around the high-$9/mn Btu
to low-$10/mn Btu level, while tentative offers are in the
mid- to high-$10s/mn Btu. October procurement has yet to
start, but indicative prices are supported by potential incremental gas demand when the monsoon season ends.
India’s des prices are assessed unchanged at $10.375/mn
Btu for second-half September and $10.425/mn Btu for firsthalf October deliveries. They are assessed at $10.425/mn Btu
for second-half October deliveries.
Atlantic fob prices steady
Atlantic basin fob prices were steady at the end of the
week, with additional buying interest anticipated for the
end of September and October.
The second half of October fob contract opened at a
narrow premium to the second half of September. But the
premium could narrow further over the course of August if
spot demand fails to increase.
Twelve September reloads were booked in Spain, according to the latest system operator schedule. After two
months of muted interest, shippers were likely looking to
offload LNG re-exports to ease high inventories.
Also supporting prices was higher Spanish gas prices.
One participant in Spain’s AOC gas hub put the price for
September at $10.20/mn Btu, which was slightly higher than
$10.00/mn Btu for August. The spread between bids and offers for gas on the AOC remained wide, but there seemed to
be more buyers than in the previous weeks.
But with northeast Asian prices of around $10.60/mn
Btu for October deliveries, recently heard offers of the high
$10/mn Btu region for Iberia peninsula fob reloads and even
around low $10/mn Btu for Nigeria fob volumes were still
too high for spot cross-basin trade. However, there was
some cross-basin trade conducted by portfolio players. The
145,000m3 Methane Jane Elizabeth, 170,000m3 Methane
Patricia Camila, and 170,000m3 Methane Julia Louise were
all hauling Equatorial Guinea cargoes to northeast Asian
destinations, with arrival times between 8-20 August. BG
is the sole offtaker for the 3.7mn t/yr EG LNG plant. The
161,870m3 Maran Gas Posidonia was also taking a Trinidad
cargo to Asia, and was expected to arrive on 19 August.
Brazil’s Petrobras was heard making enquires for fob
volumes this week, which could signal a return to the market
for the South American importer.
The latest tender from Australia’s 16.3mn t/yr North
West Shelf (NWS) plant could also give some indication for
Asian demand. Up to four cargoes could be awarded and
bids were due by next week. The NWS tender was also supporting freight rates, with a lack of available ships available
for the end of August-loading fob cargo, according to one
shipbroker.
The 6.9mn t/yr Papua New Guinea (PNG) plant also
awarded some September cargoes this week, but may have
rejected some higher bids from traders as it prefers to sell
directly to importers.
Global supply highlights
Supply
Loading period
First reported
Last updated Comments
12 reloads from Spain scheduled
Sep
25 Jul
01 Aug All full size
Unspecified number of cargoes from NWS
end-Aug to end-Nov
29 Jul
29 Jul Tender closes 4 Aug, bids valid until 8 Aug
Up to 2 cargoes from Netherlands
Aug-Sep
28 Jul
28 Jul
Three or more cargoes from Nigeria
Aug/Sep
03 Jul
25 Jul
One Aug, two Sep, maybe more from oil
major
2 cargoes from Abu Dhabi
Sep
23 Jul
25 Jul
Earlier Aug cargo heard sold to porfolio
player
2 cargoes from PNG LNG
Sep
28 May
24 Jul
For 1H & 2H Sep loading. Some cargoes possibly offered directly to term buyers
Over 5 a month from Norway
July onwards
21 Jul
21 Jul All cargoes likely to be spot
4 reloads from Spain scheduled
Aug
27 Jun
21 Jul Down from 6 reloads, all full size
1 from Bintulu LNG
Sep
08 Jul
08 Jul According to an offtaker
12-13 cargoes from Bontang LNG
2H 2014
02 May
27 Jun One offered for August
Unspecified number of cargoes from NWS
17-19 Jul; 16-21 Aug
27 May
18 Jun
3 cargoes possibly awarded, all portfolio
suppliers/traders
3 cargoes from Sakhalin Energy
Jul-Sep
10 Jun
18 Jun
2 of 3 cargoes possibly awarded to Japanese
utilities
Copyright © 2014 Argus Media Ltd
Page 3 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
Global demand highlights
Demand
Delivery period
First reported
1 cargo from PTT
Sep
24 Jul
29 Jul
For 4-15 Sep delivery. Secured at just under
mid-$10/mn Btu
8 cargoes from Gail India
Jan - Dec 2015
29 Jul
29 Jul
Tender closes 14 Aug. Deliveries primarily
to Dabhol terminal.
5 from Argentina's YPF
1 in Aug and 4 in Sep
02 Jul
18 Jul
Cargoes awarded to Shell, Trafigura and
Petrobras, $11/mn Btu to high $11/mn Btu
1-3 cargoes from Greek and Turkish
buyers
Aug - Sep
11 Jul
18 Jul
Demand is price-sensitive. 1 cargo to
Greece Sep des, 1- 2 to Turkey Aug - Sep des
1 cargo from PTT
Aug
08 Jul
14 Jul
16-24 Aug delivery, awarded at mid- to high$10/mn Btu
3-5 cargoes from Japanese utilities
Sep
09 Jul
09 Jul
1 cargo from CPC
Sep
09 Jul
09 Jul
1 cargo from Kuwait Petroleum Corp
Late Aug
08 Jul
08 Jul
1 cargo from PTT
Aug
25 Jun
02 Jul
Around 3 cargoes for Japanese utilities
Aug
12 Jun
02 Jul Possibly all fulfilled
1 cargo by CPC
Aug
18 Jun
18 Jun
1 cargo from Indian importer
Aug
09 Jun
09 Jun For delivery to Kochi terminal
Norway’s 4.2mn t/yr Snohvit plant is expected to operate
at full capacity – producing over five cargoes a month – all of
which are likely to be offered on a spot basis, according to
capacity holders at the plant this week.
Cargoes for delivery in late August and early September
from Snohvit were being offered at $9.50/mn Btu to Europe
and $10.50/mn Btu to South America. Cargoes from Snohvit
in the second half of the month and first half of October may
be marketed at a narrow premium to this level, but are still
likely to be more competitive than Iberian reload cargoes at
current market levels.
Also, the number of Spanish reloads made may drop below 12 for September as it is possible to cancel slots on the
provisional schedule.
Benchmark price snapshot
Market
Delivery
Price
$/mn Btu
Natural gas
Nymex
Sep
3.81
NBP
Sep
6.81
Zeebrugge
Sep
6.99
Peg Nord
Sep
7.25
PSV
Sep
7.73
WTI
Sep
97.47
Brent
Sep
105.06
JCC*
May
109.17
Copyright © 2014 Argus Media Ltd
Awarded at low-$11/mn Btu; Pacific basin
cargo
At least one cargo sought, demand is price
sensitive
$/mn Btu
Argus Iberian peninsula des
11.5
11.0
10.5
10.0
9.5
9.0
20 Jun 14
4 Jul 14
18 Jul 14
1 Aug 14
$/mn Btu
West Africa (AWAF) LNG fob
11.5
11.0
10.5
10.0
$/bl
Crude
*Japanese Cocktail Crude
Last updated Comments
9.5
9.0
20 Jun 14
Page 4 of 17
4 Jul 14
18 Jul 14
1 Aug 14
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
Global shipping highlights
Vessel
Capacity m³ From
To
Loading
Arrival Notes
Galicia Spirit
138,000 Ras Laffan, Qatar
Bahia Blanca, Argentina
08 Jul
03 Aug
Grace Barleria
149,700 Das Island, UAE
Mina al-Ahmadi, Kuwait
21 Jul
03 Aug
04 Aug Re-export
Wilenergy
125,000 Sagunto, Spain
Chita, Japan
05 Jul
Gaselys
153,500 Arzew, Algeria
Incheon, South Korea
02 Jul
05 Aug
Ish
137,500 Das Island, UAE
Sodegaura, Japan
20 Jul
05 Aug
Meridian Spirit
165,500 Snohvit, Norway
Pecem, Brazil
21 Jul
05 Aug
Escobar, Argentina
19 Jul
05 Aug
SCF Arctic
71,500 Point Fortin, Trinidad
BW GDF Suez Everett
138,000 Balhaf, Yemen
Himeji, Japan
12 Jul
06 Aug
Grace Dahlia
177,000 Snohvit, Norway
Northeast Asia
06 Jul
06 Aug Likely northeast Asia
Arctic Aurora
155,000 Point Fortin, Trinidad
Bahia Blanca, Argentina
22 Jul
08 Aug
LNG Akwa Ibom
142,656 Bonny, Nigeria
Asia
30 Jun
08 Aug
Yenisei River
155,000 Ras Laffan, Qatar
Zeebrugge, Belgium
22 Jul
08 Aug Backhaul charter
Arctic Discoverer
140,000 Snohvit, Norway
Penuelas, Puerto Rico
25 Jul
09 Aug
LNG Jupiter
145,000 PNG, Papua New Guinea
Futtsu, Japan
29 Jul
09 Aug Spot cargo
Maran Gas Efessos
160,000 Equatorial Guinea
Tong Yeong, S Korea
11 Jul
09 Aug
Methania
131,200 Bonny, Nigeria
Sagunto, Spain
30 Jul
09 Aug
Seri Bijaksana
152,300 Arzew, Algeria
Sakai, Japan
11 Jul
10 Aug
Golar Viking
140,000 Ras Laffan, Qatar
Quintero, Chile
18 Jul
12 Aug
Sestao Knutsen
138,100 Point Fortin, Trinidad
Suez Canal
29 Jul
14 Aug
18 Aug
LNG Ogun
149,600 Bonny, Nigeria
Incheon, South Korea
22 Jul
Maran Gas Posidonia
161,870 Point Fortin, Trinidad
Asia
22 Jul
19 Aug
British Innovator
138,200 Point Fortin, Trinidad
Mejillones, Chile
31 Jul
20 Aug
Ribera Del Duero Knutsen
173,410 Bonny, Nigeria
Pyeong, South Korea
21 Jul
23 Aug
Seri Begawan
152,300 Cartegena, Spain
Joetsu, Japan
20 Jul
02 Sep Re-export
$/t
Middle East bunker fuel - Fujairah
380cst
650
180cst
640
55,000
630
52,500
620
50,000
West Suez
47,500
600
45,000
590
42,500
580
570
23 Apr 14
28 May 14
30 Jun 14
1 Aug 14
$/t
European bunker fuel - Rotterdam
680
East Suez
57,500
610
$/d
Freight
180cst
380cst
1.5% 180cst
40,000
11 Jun 14
27 Jun 14
15 Jul 14
$/t
Asia Pacific bunker fuel
1.5% 380cst
675
380cst Sing
180cst SKorea
1 Aug 14
180cst Sing
380cst SKorea
660
650
640
625
620
600
600
575
580
560
24 Apr 14
29 May 14
Copyright © 2014 Argus Media Ltd
01 Jul 14
01 Aug 14
550
23 Apr 14
Page 5 of 17
28 May 14
30 Jun 14
1 Aug 14
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
News
Potential strike action may affect QCLNG start-up
The end-2014 start of UK-listed BG’s 8.5mn t/yr Queensland
Curtis LNG (QCLNG) project in Australia could be at risk if
unions vote to strike this month.
Four unions, including the Construction, Forestry, Mining
and Energy Union (CFMEU), have yet to agree on an enterprise agreement with US-engineering firm Bechtel, the
construction contractor for QCLNG. The unions will vote on
a strike on 12-14 August, with results expected a day later.
Bechtel is the contractor for all three LNG projects being
built at Gladstone. The company said it has received notice
from CFMEU of its intention to take protected industrial action as part of Australia’s Fair Work Act enterprise bargaining
process on 7 August, but did not give any further details.
Fly-in, fly-out workers at QCLNG work for four weeks and
then take one week off, CFMEU said. It is pushing Bechtel to
shorten the working roster to three weeks on and one week
off.
The four unions have legal recourse for strike action,
with Bechtel having made its best and final offer, BG chief
financial officer Simon Lowth said. The company will provide
an update on how a strike would affects its plan following
the vote.
There are 148 eligible members of the CFMEU who are
able to take protected action following a ballot. There are
about 8,000 workers across the three projects eligible to
vote on a new agreement, Bechtel said.
The other unions representing the Gladstone workforce
are the Australian Manufacturing Workers Union, the Australian Workers Union and the electricians and plumbers branch
of the Communications, Electrical and Plumbing Union.
The QCLNG plant will pass through four stages before
first shipments, Lowth said. The first stage is the commissioning of gas turbine turbines, followed by gas going into
plant, then the start-up of compressors —expected in September— and finally injections of feed gas into the trains for
the freezing and liquefaction process.
“All of these stages are major complex processes. We are
proceeding well, however there may be technical unknown
unknowns, and clearly if any event happens in those four
stages we will be coming back to the market,” Lowth said.
BG has drilled over 2,000 wells from its coal-bed methane fields onshore Queensland, enough to fill both trains,
Lowth said. BG has started production at more than 1,100
wells, mainly in the Ruby Jo fields, the central area fields
and the Bellevue field for QCLNG’s first train. It plans to
start production in early 2015 from the Wallaby Creek field
in northern area of its onshore Queensland fields for the
start-up of the second train next year.
The project remains on budget for $20.4bn and capital
expenditure will be around $1bn-1.5bn/yr.
Twelve Spanish LNG reloads scheduled for September
Shippers have booked 12 standard-sized cargo LNG reloads
from Spain in September, according to today's Enagas system
operator schedule. This was three more than the preliminary
September schedule published earlier this week.
The newest schedule includes the first ever reloads from
the 12.4mn t/yr Barcelona and 5mn t/yr Bilbao import terminals.
One reload from Bilbao had previously been scheduled
for the end of July, but was cancelled to allow for commissioning of a new LNG storage tank. The new third tank will
increase storage capacity to 450,000m³ from 300,000m³ at
Bilbao and is expected to be operational by the end of August. The latest Enagas schedule showed that Bibao storage
levels will breach the old limit of 300,000m³ by mid-September which means that if the tank is not completed in time,
Latest estimated LNG distribution by destination
Asia-Pacific
12,726,787
Europe
2,928,512
North America
878,848
South America
872,648
Upstream
20,435,286
Based on vessels at sea, final destination and estimated arrival time. Upstream
figure includes all major production regions.
Netbacks
$/mn Btu (front half month)
India
Middle East
m³
China
Japan
South
Korea
Taiwan
Iberian
peninsula
Greece
Italy
Turkey
NW
Europe
Northeast US
US Gulf
10.13
9.35
9.21
9.28
9.46
8.25
8.57
7.65
8.67
6.99
1.43
2.08
Australia
9.64
9.84
9.77
9.78
9.96
7.59
7.89
7.08
7.99
6.43
0.98
1.63
Nigeria
9.00
8.53
8.40
8.46
8.64
8.82
8.64
7.92
8.71
7.59
2.16
2.91
Norway
8.64
7.96
7.82
7.89
8.06
9.02
8.78
8.06
8.85
8.03
2.41
3.06
Algeria
9.16
8.47
8.33
8.40
8.58
9.36
9.38
8.56
9.45
8.11
2.41
3.08
Trinidad and Tobago
8.36
7.98
7.85
7.91
8.09
8.82
8.62
7.89
8.69
7.63
2.60
3.50
Russia
9.22
10.18
10.23
10.24
10.13
7.16
7.48
6.66
7.57
6.02
0.91
1.54
Copyright © 2014 Argus Media Ltd
Page 6 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
the schedule will have to be changed again to accommodate
the LNG.
Barcelona started offering reloads from July and this is
the first one scheduled at the terminal.
The high number of booked reload slots likely reflected
the desire of shippers to re-export more LNG in September,
after relatively low reload volumes in July and August.
Iberia reload sellers have been unwilling to lower offers
much below around $11/mn Btu. But buyers have been bidding at the $9/mn Btu region, with northeast Asia demand
this summer lower because of mild weather and spot
demand being met by Pacific basin supplies including from
Papua New Guinea.
Sellers of reloads have the option of holding supply in
storage rather than offering it on the spot market, increasing flexibility compared with other Atlantic fob producers.
Sellers of cargoes from Norway’s 4.2mn t/yr Snohvit or
Nigeria’s 22mn t/yr Bonny facilities are likely to have less
flexibility, with the loading window for the cargo agreed well
in advance. The cost of holding a cargo in storage in Spain is
estimated to stand at about €30,000/day, which would add
about 30-35¢/mn Btu to the price of a cargo per month. The
flexibility not to sell cargoes at current market levels — as
well as the cost of holding cargoes in storage — has supported offers for Spanish reload cargoes relative to offers for
cargoes from Bonny or Snohvit.
Shippers also have the option of selling regasified LNG
into the Spanish AOC gas hub. The August contract was in
the €25.50/MWh ($10.00/mn Btu) region yesterday, but with
a very wide bid-offer spread. This has kept the Iberia reload
offers high and cross-basin trade unviable for spot trades.
But volumes that can be sold into the AOC are limited.
The highest volumes that are typically sold stand at about
300 GWh/month — equivalent to less than a third of an
average-sized LNG cargo. Most deals are for 100 GWh/month
or less. The lack of firm bids is likely to further reduce volumes sold, as buyers are well-supplied and not seeking high
volumes.
Enagas expected gas demand for August at 487.7 GWh/d,
so may not be able to absorb much extra LNG, with the majority likely already arranged to be supplied by pipeline gas.
Yesterday, the Argus Iberia peninsula reload fob bids for
the first half of September were at $9.30/mn Btu, with offers
at $10.60/mn Btu. The Argus northeast Asia (Anea) price for
LNG delivered in the first half of October was $10.62/mn
Btu.
Enagas schedules are updated regularly and are subject
to significant changes throughout the month.
Algeria LNG production and exports rebound
Algerian LNG production and exports have rebounded in
2014, supporting deliveries to northeast Asian buyers.
LNG production rose to the highest level in at least two
Copyright © 2014 Argus Media Ltd
NBP
Delivery
Day-ahead
$/mn Btu
Bid
Offer
Midpoint
±
6.30
6.33
6.312
-0.328
-0.175
Sep
6.81
6.83
6.820
Oct
8.03
8.08
8.054
-0.111
Nov
9.50
9.55
9.528
-0.077
4Q14
9.23
9.26
9.246
-0.084
1Q15
10.27
10.30
10.286
-0.044
2Q15
9.11
9.13
9.122
-0.019
Winter 2014-15
9.74
9.77
9.755
-0.062
Summer 2015
9.06
9.08
9.071
-0.018
10.51
10.54
10.523
-0.002
9.64
9.66
9.648
-0.023
Winter 2015-16
2015
2016
9.94
9.97
9.952
-0.048
2017
10.07
10.11
10.090
-0.025
years in the first quarter of 2014, according to government
figures. Production stood at 3.35mn t of LNG in the first
quarter, based on Argus calculations using data from the
energy ministry and national statistics office.
Total volumes exported in the first quarter stood at
2.63mn t, up from 2.1mn t in 2013, reaching the highest level
for a first quarter since 2011, according to customs data.
Higher production has enabled Algeria to boost exports
to premium northeast Asian markets. It delivered 488,000t
to northeast Asian buyers last winter — up from just
122,000t in the winter of 2012-13.
This marks a re-emergence of Algerian exports to premium Asian markets, after export volumes faltered entirely
from July to December 2012, and in 2009 and 2010. But exports to northeast Asian buyers remain well below the highs
seen in 2007 and 2008.
The growth in exports to northeast Asia was largely
driven by higher volumes delivered to Japan. Algerian exports to Japan stood at 309,400t in the first quarter of 2014,
compared with just 60,200t in the equivalent quarter a year
earlier.
Japanese trading house Marubeni made an agreement
in 2013 for the purchase of Algerian LNG. It is currently in
discussions with the trading house with an eye to forming
another export contract for delivery in the winter of 201415. Petrochina was marketing Algerian volumes on a spot
basis earlier this year which it did not need to meet its own
needs. Malaysia’s Petronas was also likely to have bought
Algerian volumes on a fob basis from Sonatrach.
Only two of Sonatrach's vessels are said to be capable of
delivering to buyers in the Pacific. The state-owned company’s LNG carrier fleet is ageing, so it has increasingly been
forced to offer cargoes on a fob basis. Last winter cargoes
were loaded from Algeria on trader-operated vessels. GDF
Suez, Eni and Endesa have delivered Algerian cargoes to
Page 7 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
northeast Asian buyers received under their long-term
agreements with Sonatrach.
Sonatrach said in March that it is likely to continue to
market LNG volumes to Asian buyers to take advantage of
higher demand and delivered prices than in Europe. But
demand for Algerian volumes in northeast Asian markets
may be lower this winter than last. Demand in the region
for cargoes from the Atlantic basin could be dampened by
higher volumes available from liquefaction projects in the
Pacific basin.
Rising domestic demand reduced the country’s pipeline
exports in 2013, compared with 2012, and could hamper the
growth of LNG exports. Sonatrach’s domestic sales increased
by 10.7pc to 32.1bn m³ in 2012, compared with 29bn m³ in
2011, more rapidly than the 7.1pc/yr increase expected in
the 10-year plan published by Algeria’s energy regulator in
2010.
Sonatrach still plans to increase liquefaction capacity
in a bid to further boost LNG exports. The first 4.7mn t/yr
train at the fourth Arzew liquefaction complex is expected
to start up in the second half of this year. But the new train
at Arzew could find itself competing with the new 4.5mn t/
yr train at Skikda for limited volumes available for export.
In the context of rapidly rising demand, the extent to which
new liquefaction capacity will increase exports remains
uncertain.
Despite the increase, volumes exported from Algeria
remain well below levels seen in 2005 and 2006.
Sonatrach has also attempted to increase gas production
as part of its bid to increase LNG exports, but plans have
stalled in recent years in the wake of a corruption scandal
and substantial management turnover in 2010. The company
remains resolved, and recently announced plans to invest
over $22bn over the next few years to increase gas reserves
and production capacity. It says the investment could enable
it to recover an additional 400bn m³ from the Hassi R'mel
field, which has been in production since 1956. And it plans
to bring six new fields with a combined capacity of almost
75mn m³/d online, without specifying a timeframe.
Even as LNG production and exports rebound, Sonatrach
may not have fulfilled its long-term pipeline gas supply
contracts in 2013, market sources said. It agreed to reduce
Italian gas and oil company Eni’s take or pay obligations
halfway through the 2012-13 gas year, effectively freeing up
supply for sale on the global LNG market. The country is now
on course to take 9bn m³ in the 2013-14 gas year — considerably lower than the 23 bn m³ per year for the five gas years
ending in 2011-12.
Gas processing capacity is also expected to increase to
levels above those before the attack on the In Amenas facility in January 2013. The facility was producing 18mn m³/d of
gas in mid-July, equivalent to 4.73mn t/yr of LNG. The re-
Copyright © 2014 Argus Media Ltd
start of the second production train at the facility began on
22 April, which will enable production to ramp up to 23mn
m³/d or 6.09mn t/yr of LNG.
Chevron to seek new partner in Kitimat LNG
Chevron plans to push forward with its Kitimat LNG export
project in western Canada, but the US oil major will need
to find a new partner and line up export customers before it
can make a final investment decision (FID).
Regardless of plans announced yesterday by US upstream independent Apache to exit Kitimat and another
LNG project operated by Chevron, Australia’s Wheatstone, a sanctioning decision cannot be made until buyers are lined up for at least 60pc of the 5mn t/yr plant’s
output, Chevron said today. The major, which previously
planned to make an investment decision on Kitimat this
year, is now noncommittal about when that step will be
taken.
“We need to get clarity, we need to get closure on a
partnership,” Chevron vice chairman George Kirkland said.
“And we need to deal with buyers and understand costs and
economics. We’re not going to go to FID on a project until
we have gas sales and we understand the economics of those
sales.”
Before Chevron can deal knowledgeably with prospective buyers, it needs to get further along in assessing the
shale-gas holdings that will feed the Kitimat liquefaction
plant, and it needs to nail down project costs and timing,
Kirkland said. Appraisal is already done on one of the British
Columbia shale formations where Kitimat’s natural gas will
be produced, the Horn River. Drilling planned for this year in
the Liard Basin will give Chevron a better understanding of
the other planned gas source.
Chevron owns a 50pc stake in the project and has no
interest in acquiring any of Apache’s 50pc interest, Kirkland
said. The company is already operator of the liquefaction
side of the project and may step in to operate the upstream
component when Apache leaves. LNG buyers will have the
option of acquiring some of Chevron’s stake in the development, as is increasingly common in long-term supply agreements.
Complicating efforts to line up long-term supply contracts for LNG projects is the addition of gas-export developments in the US, which was expected to be a major gas
importer before fuel production surged on the shale boom.
US projects may shake up the supply-demand balance in
global LNG markets.
“With the degree of uncertainty about US exports and
the size of exports, you can understand why buyers would
want to wait and see how things sort out before signing
long-term contracts,” Chevron chief financial officer Pat Yarrington said.
Page 8 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
India looks for Japanese help to build LNG vessels
The Indian government has asked Japanese shipyards to
work together with local firms to build vessels to import LNG
from the US.
India’s state-controlled Gail plans to buy as many as 12
LNG vessels, down from an initial estimate of 14, to import
LNG from the US starting in 2017, oil minister Dharmendra
Pradhan said. Gail will source at least three vessels from
Indian yards.
Pradhan urged Tokyo to encourage Japanese firms to
participate in Gail’s tender and to help with the construction
of the three vessels by transferring technology and encouraging shipyards in the two countries to work together.
Pradhan also asked Kazuyoshi Akaba, Japan’s trade and
industry minister, to collaborate on a common strategy so
that LNG can be procured at competitive prices.
“India and Japan can work together to facilitate LNG
trading in the Asian region with a focus on destination flexibility to ensure efficient gas supply for the region,” Pradhan
said.
Japan and India have been looking to co-operate on LNG
procurement for some time, with Tokyo and Delhi agreeing
in September last year to ensure stable and competitivelypriced LNG supplies. Japanese trading house Sumitomo and
Gail signed an initial agreement this week to collaborate
on a global natural gas and LNG business to ensure stable
supplies. The tie-up will also strengthen the companies’
relationship in the US, where they are partners in US energy
firm Dominion Resources' 5.75mn t/yr Cove Point LNG export
project in Maryland.
Japanese utility Chubu Electric Power and Gail agreed in
March to pursue possible joint purchases of LNG as well as
optimising shipping, in order to buy the fuel at lower prices.
Gail plans to buy 170,000m³ tankers from Indian shipbuilders, including private-sector engineering firms Larsen
and Toubro and Pipavav Defence and Offshore Engineering.
But none of the Indian yards have experience building LNG
tankers.
The 12 vessels, half of which will be bought in a first
phase under 20-year charters, will carry 5.8mn t/yr of US
LNG that Gail has secured in long-term supply deals. It has
agreements with US LNG firm Cheniere Energy's planned Sabine Pass project as well as the Cove Point venture, amounting to 3.5mn t/yr and 2.3mn t/yr respectively on a fob basis.
Oregon LNG wins DOE export approval
The US Department of Energy (DOE) today authorized the
proposed Oregon LNG project to export 1.3 Bcf/d (35mn
m³/d) of mostly Canadian gas to countries that do not have
free trade agreements (FTAs) with the US.
The project in Warrenton, Oregon, is the eighth to
obtain that critical approval. Oregon LNG will be allowed to
Copyright © 2014 Argus Media Ltd
send gas to some of the world’s biggest LNG consumers for
20 years. Japan, the world’s largest LNG buyer, and other
countries that are part of lucrative Asian and European LNG
markets do not have FTAs with the US.
Oregon LNG plans to begin exporting in 2019 but it has
yet to receive approval from the US Federal Energy Regulatory Commission (FERC) to begin construction.
Project backer LNG Development had submitted the
application for exports to non-FTA countries before the DOE
mandated that proposed terminals must first meet FERC
requirements. The DOE deems whether LNG exports are in
the public interest. In making its decision, the DOE said it
considered the source of the gas and nearly 200,000 public
comments.
Oregon LNG, unlike other US export projects, will
source the bulk of its gas from western Canada. Canadian
regulator the National Energy Board in May tentatively
approved the project to export up to 1.5 Bcf/d of Canadian gas to its terminal. The gas would be delivered on
various pipelines to two trading hubs along the US-Canada
border. Those volumes would enter the US through either
Williams’ Northwest pipeline in Sumas, Washington, or
TransCanada’s Gas Transmission Northwest pipeline in
Eastport, Idaho.
The terminal site, at the mouth of the Columbia river, is
not connected to either pipeline. Oregon LNG would build
the 85-mile (137km) Oregon Pipeline to link the facility to
Northwest pipeline, near Woodland, Washington.
Gross gas output at record high: EIA
US natural gas production shot to a fresh record high in May
as operators in the Marcellus and Utica shales brought more
wells on line and output continued to increase in Texas and
Oklahoma.
Gross gas production — which includes volumes that do
not make it to market — rose in May to 78.1 Bcf/d (2.2bn
m³/d), up by 920mn cf/d from April and a year-over-year
increase of 6.2pc, according to the US Energy Information
Administration (EIA). Gas output has reached new highs this
year as producers continue to coax gas and oil from underground shale formations.
The Marcellus, a mammoth gas field in Pennsylvania and
the surrounding states, has remained lucrative even at low
commodity prices. In addition, profitable wells in oil-rich
areas such as south Texas’ Eagle Ford shale and west Texas’
Permian basin often yield large volumes of gas.
The EIA’s “Other States” category — which includes
output from the Marcellus, the Utica shale in Ohio and North
Dakota’s oil-rich Bakken formation — posted the largest gain
in May. Production from other states rose to 30.42 Bcf/d, an
increase of 2.6pc from April and up by a fifth from a year
earlier.
Page 9 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
Production from Texas, the top gas-producing state in
the US, rose in May to 23.44 Bcf/d, up by 170mn cf/d from
April, while Oklahoma output was up by 50mn cf/d to 6.32
Bcf/d. Production from Louisiana, Wyoming and the US Gulf
of Mexico also increased slightly in May.
New Mexico posted the biggest month-over-month decline. Output from that state in May dropped to 3.52 Bcf/d,
down by 3.6pc from April, the EIA said.
Qatari arbitration results, Edison's earnings were still 22pc
higher year on year, the company said.
Italian gas demand — including injections and exports
— dropped to 32.6bn m³ during the first half of 2014, down
by 13.8pc on the year, as a result of mild weather, which reduced residential gas consumption, as well as weak demand
from power plants. Italian gas-fired power generation has
been displaced by growing renewable generation capacity.
Eni pushes for hub-linked price corridors
Too soon to assess Russia sanctions impact: Shell
Italy's Eni wants to negotiate hub-linked price corridors into
all existing long-term gas supply contracts by 2016, it said.
None of the company's contracts are hub-indexed, but
60pc of its long-term supply portfolio has a hub-linked price
corridor. Eni had previously said it planned to bring its longterm supply agreements into line with market conditions
without specifying the mechanism.
Recent <a href="http://direct.argusmedia.com/newsandanalysis/html/1053282">contract renegotiations</a> with
Russia's state-controlled Gazprom and Norway's state-controlled Statoil resulted in reduced take obligations in terms
of volumes as well as the introduction of hub-linked price
arrangements.
The firm is continuing renegotiations with Algeria’s stateowned Sonatrach and Libya’s state-owned NOC and hopes to
agree hub-linked price corridors for these contracts. Eni also
hopes to clear all of its €1.9bn ($2.5bn) of untaken long-term
contract gas for which it had paid by the end of 2013. The
reduction in take-or-pay volumes from some of its suppliers
could help the firm make up ground on its take-or-pay commitments after falling short in some previous years.
Shell said it is too early to know what impact the latest
round of sanctions on Moscow will have on its operations in
Russia.
The US and EU have agreed to restrict some “technologies” being exported to Russia, particularly in the oil sector.
And the EU has joined the US in restricting Russia’s access
to capital markets. But Shell said today that the fine details
are still unclear. “We will know how to react when we know
what it is that we have to react to,” chief executive Ben van
Beurden said. “Events are still unfolding. There are more
disclosures coming. There are political decisions that we are
expecting today. There are going to be reactions to those,
no doubt. And I guess it will go on for a little while before it
settles down.”
Shell’s main interests in Russia comprise a 27.5pc stake
in the 9.6mn t/tyr Sakhalin 2 LNG project, led by statecontrolled Gazprom, and its Salym Petroleum Development (SPD) joint venture with state-run Gazpromneft.
SPD is mainly involved in conventional oil operations in
west Siberia. But it has recently begun horizontal drilling in the Bazhenov shale formation at the Upper Salym
field. And Shell established another joint venture with
Gazpromneft last year to expand its tight oil prospects
in west Siberia. The firm said it is hard to assess at the
moment how the restrictions on technology exports might
hamper SPD’s tight oil operations. “It is clear that there
will be sanctions targeted on that. As Shell, we will have
to obey these sanctions. How it will impact whatever it is
that Salym is doing in the unconventional area depends on
the nature of the sanctions and the details around it,” van
Beurden said.
Shell is more confident that its Sakhalin 2 project — and
a potential 5mn t/yr expansion — will not fall foul of the
technology sanctions. “It talks about predominantly oilrelated technology. It looks as if it very much tries to avoid
hitting gas exports. But there may be some implications
from the financial sanctions,” Van Beurden said.
Shell confirmed today that the conflict in Ukraine and
the downing of Malaysian Airlines flight MH17 has had a significant impact on exploration work on the Yuzovskaya shale
block. “It was technically on hold for evaluation purposes
Edison's gas sales margins under pressure
Italian energy firm Edison said that its gas sales margins
remained under "strong pressure" during the first half of
2014, although its gas supply and sales business had partially
recovered despite a drop in Italian demand.
Having previously renegotiated its long-term supply
contracts with Algeria and Qatar, Edison said it was in the
second phase of the price review process for its long-term
supply contracts with Libya and Russia, with the aim of restoring "reasonable margins" on the portfolio of its multi-year
contracts. The company expects to complete the contract
negotiations in 2014-15.
Edison secured a "positive result" in its arbitration case
against Qatar's state-owned Rasgas in 2012 in a dispute
over the price it paid for LNG under a 25-year, 4.6mn t/yr
contract. Similarly it won its arbitration with Algeria's stateowned Sonatrach over the price of long-term gas supply in
May 2013.
Discounting the one-off effects of the Algerian and
Copyright © 2014 Argus Media Ltd
Page 10 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
but we have also declared force majeure, simply because we
cannot continue the operations there.”
EDP sells more gas in Spain
Portuguese energy company EDP’s sales of gas in Spain rose
to 17TWh in the first half of 2014 from 14.7TWh in the same
period last year.
The increase in sales came despite Spanish gas demand
continuing to fall year on year, as a result of a milder winter
and the continued displacement of gas-fired power plant
from the generation mix by cheaper coal and rising renewable output.
But EDP said it was able to divert its long-term gas supply
to the wholesale market, rather than using it for generation
or supply it to consumers.
The firm has a "highly flexible" contract with Algeria's
state-owned Sonatrach for 1.6bn m³/yr, delivered both as
LNG and through the Medgaz pipeline, and a contract for
Trinidadian supply from the Atlantic LNG facility. In all, it
has contracted about 3.6bn m³/yr of supply.
EDP’s trading sales in Spain and Portugal rose to 10.6TWh
in the first half of 2014 from 4.4TWh in the first half of 2013.
Many importers in Spain and Portugal have reacted to the
decline in Iberian gas demand by diverting and re-exporting
LNG to higher-priced markets further afield.
But as this trade has developed, some have taken on
additional supply in Spain so as to take further advantage of
arbitrages to higher-priced markets.
EDP's sales to consumers in Spain and Portugal in the first
half of 2014 dropped to 8.5TWh from 12TWh a year earlier.
Gas burnt in the company’s own power plants fell to 1.7TWh
from 3TWh in the same period.
Woodside shareholders reject Shell buy-back plan
Australian independent Woodside Petroleum has failed to
receive enough backing from shareholders to buy back 9.5pc
of its shares from Shell, failing to reach the 75pc approval
level needed.
Woodside said it received 72pc approval from shareholders attending a general meeting in Perth today and 28pc
voted against the plan. Only 71.3pc of shareholders voting
by proxy or through a direct vote approved the $2.68bn
buy-back, with 28.7pc against. About 59pc of shareholders
entitled to vote did it by either by proxy or direct votes.
Woodside planned to buy back 78.3mn shares as part of
Shell's sale of a 19pc stake in the Australian firm. Shell has
completed the sale of a 9.5pc stake to financial institutions.
The lack of approval means that Shell's holdings in Woodside
holds at 14pc.
Shareholders were against the sale because the trans-
Copyright © 2014 Argus Media Ltd
action has been structured to minimise tax liabilities for
Woodside and Shell, failing to benefit long-term institutional
shareholders looking to benefit from tax paid dividends from
Woodside. The shareholders were also concerned that they
may be liable for tax payments on future dividends from
Woodside.
Shell has not decided what it will do with its remaining stake. But it is not relying on the sale to meet its $15bn
divestment target in 2012-14, having already closed around
$8bn of asset sales in the first half of this year.
Shell built up its stake in Woodside in the early 2000s. It
made a $10bn takeover bid for the firm, Australia's largest
LNG producer, in 2001. But the takeover was one of the few
foreign bids for Australian resource companies to be rejected by the country's government on national interest grounds.
Shell sold a 10pc stake in Woodside in 2010.
BG, BHP Billiton secure Trinidad deepwater blocks
Major LNG exporter Trinidad and Tobago has awarded two
deepwater blocks to a consortium of Australian firm BHP Billiton and the UK’s BG.
The ministry had invited bids for six blocks in August
2013. Four of the blocks failed to attract any proposals.
The BG-BHP Billiton consortium secured blocks TTDAA 3
and TTDAA 7. The energy ministry said Spain´s Repsol made
an unsuccessful bid for TTDAA 3.
The two adjacent blocks lie off the east coast of Trinidad
in water depths of 1,780-2,100m.
The awards signal the start of negotiations with the
energy ministry for production-sharing contracts.
The consortium committed to first-phase minimum work
programs that include the acquisition of 2,400km2 of 3D
seismic and additional geologic studies. For the second and
third phases, the consortium will drill a total of four wells,
each to a depth of 2,200m, on the two blocks.
The new awards bring to eight the total number of deepwater blocks contracted since the country started signing
deepwater production-sharing contracts in 2010. But there is
no deepwater production yet.
BHP Billiton and BG already hold other deepwater acreage offshore. Other deepwater contract holders are BP and
Repsol.
“Our policy is to be constantly putting out acreage for
bidding, but this is likely to be our last deepwater bidding
round for 2014 and 2015,” energy ministry Kevin Ranmarine
has said.
Trinidad and Tobago produced 4.18bn ft³/d (117mn m3/d)
of gas in January-April, down 2.3pc from a year earlier.
Crude production fell by 2.5pc to 79,632 b/d in the same
period.
Page 11 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
Australia weekly - market commentary
Argus Wallumbilla Index (AWX)
Wallumbilla forward prices dip below A$2/GJ
Gas prices for month-ahead deliveries on the Wallumbilla
voluntary trading hub slipped this week to under A$2/GJ
($1.96/mn Btu), amid sustained pressure from more than
ample supplies in Queensland state.
The three LNG projects in Gladstone, Queensland have
been ramping up upstream gas processing activities ahead
of their start-up, with the gas supplies produced marketed
to east Australian domestic markets as they cannot be
absorbed for liquefaction yet. The three projects are the
8.5mn t/yr Queensland-Curtis LNG (QCLNG), targeted to
start exports by December 2014, and the 7.8mn t/yr Gladstone LNG and the 9mn t/yr Australia-Pacific LNG that are
expected to start by late 2015.
Prompt and days-ahead Wallumbilla gas has been trading
at under A$2/GJ since about 1½ weeks ago, although forward prices had been supported by potential gas demand for
heating purposes during winter. But a significant downside
is now expected for September Wallumbilla gas deliveries,
with the onset of spring weather and continued ramp-up gas
availability.
Australia’s bureau of meteorology is predicting warmer
than normal weather during August-October, with a more
than 80pc probability that maximum temperatures will
be above median levels for the east coast of Queensland,
southern Victoria and Tasmania. The bureau also forecasts
a more than 60pc chance of warmer weather for most of
Queensland, Victoria, New South Wales and southeast South
Australia.
Queensland gas supplies are expected to be also more
than adequate in the month ahead as the LNG projects
continue ramp-up activities ahead of their start-up. QCLNG
operator, BG’s QGC, could start to flow gas into its first liquefaction train — with capacity over 4mn t/yr — as early as
October, as part of the commissioning process. But market
participants do not expect prices to lift significantly, as
ramp-up will continue from the other projects.
Significant boosts to Queensland spot gas prices should
happen only when plants begin most of their liquefaction
operations, possibly around end-2015 or 2016. This means a
significant chunk of domestic gas will be absorbed for LNG
production, reducing supplies and lifting prices. But this
hinges on the projects starting up on schedule, which may
not be the case as several Australian LNG plants have earlier
faced construction delays because of cost blowouts and
labour shortages. Spot prices could rise to the A$6-A$9/GJ
range when all three LNG plants start exporting, reflecting
the netback LNG price to Gladstone port. Recent long-term
gas contracts have already been agreed in this price range.
Victorian wholesale gas prices for month-ahead deliveries kept relatively steady this week. But downwards pressure
Copyright © 2013 Argus Media Ltd
Delivery
Units
Bid
Offer
Midpoint
±
Sep
A$/GJ
1.69
1.95
1.819
-0.281
Sep
$/mn Btu
1.65
1.91
1.780
-0.303
Argus Victoria Index (AVX)
Delivery
Units
Bid
Offer
Midpoint
±
Sep
A$/GJ
3.84
4.30
4.070
-0.013
Sep
$/mn Btu
3.76
4.21
3.984
-0.067
Price
±
AEMO weekly average Victoria 6am price
Delivery
Units
Prompt
A$/GJ
3.59
-0.55
Prompt
$/mn Btu
3.54
-0.58
Units
Price
±
A$/GJ
16.40
+0.09
$/mn Btu
16.15
-0.04
A$/GJ
10.05
+0.07
9.90
-0.01
LNG netbacks weekly average
Gladstone oil-linked LNG
Gladstone spot LNG
$/mn Btu
on forward prices is gaining because of warmer than normal
spring weather expected from August-October and ample
supplies.
Prompt Victorian prices have been largely weather
driven, fluctuating between the low to mid-A$3/GJ and the
mid- to high A$4/GJ during the past week. The Victorian Declared Wholesale Gas Market’s 6am price was at A$4.74/GJ
today because of a cold snap with maximum temperatures
barely above 10°C. Today’s gas demand forecast was around
1,186TJ (31.7mn m³), some 300TJ more than a day ago.
The AWX, the index for gas traded on the Wallumbilla
hub, is assessed at A$1.819/GJ ($1.780/mn Btu) for September deliveries, down by A28.1¢/GJ from 25 July. The Wallumbilla hub connects buyers and sellers on three major pipelines — the 233TJ/d Roma-Brisbane, the 145TJ/d Queensland
Gas and 384TJ/d South West Queensland.
The AVX, the index for gas traded on the Victorian
Declared Transmission System (DTS), is assessed at A$4.07/
GJ ($3.984/mn Btu), down by A1.3¢/GJ from 25 July. 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
Beach Energy lowers oil and gas forecast
Australian independent Beach Energy is forecasting production of 23,560-25,750 b/d of oil equivalent (boe/d) in the
2014-15 year ending 30 June, down from the 26,300 boe/d it
achieved in the previous year.
It achieved a 20pc growth in production in 2013-14
Page 12 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
because of strong output from the Cooper basin in South
Australia. But production is to fall slightly this year because
of natural decline of its Bauer oil field in the Cooper basin,
although the company has plans to expand the fluids capacity of the Bauer processing facility by 50pc later this year.
Beach has signalled that its capital expenditure guidance
for 2014-2015 year will be in the range of A$450mn-500mn
($423mn-470mn). It spent A$507mn in 2013-14.
“New oil production is expected to be delivered from the
Stunsail, Pennington, CKS [Congony, Kaladeina and Sceale]
and Rincon fields this financial year,” Beach’s managing
director Reg Nelson said.
This week the company also agreed to partner fellow
Australian independent Drillsearch in further oil acreage in
the Cooper basin and it plans to begin exploration on the
relatively underexplored tenements this year.
Beach is looking at growth options to help it take advantage of the gas supply shortage that is due to hit the east
coast state of New South Wales (NSW) from next year. It
plans to deliver gas from its Cooper basin assets, as well as
from conventional targets in the onshore Otway basin in Victoria. The gas shortage is because of the coming on stream
of three large LNG plants at Gladstone, combined with
NSW’s reluctance to exploit its coal-bed methane reserves
because of environmental concerns.
Just over half of the company’s production was oil and
the rest was gas and condensate during 2013-14.
Cooper basin gas could supply LNG projects
The Cooper basin region of northeast South Australia and
southwest Queensland is likely to produce about 155PJ/yr
(4.2bn m3/yr) of gas by 2022 and has the potential to supply
54PJ/yr to LNG projects at Gladstone, Australian independent Drillsearch said.
The Cooper basin produced 98.3PJ in the 12 months to
March, according to estimates from consultant EnergyQuest.
Drillsearch’s estimate of Cooper basin gas supply for
the three LNG projects being built at Gladstone would only
be enough for about 4pc of total gas requirements for the
projects at full capacity.
The 8.5mn t/yr Queensland Curtis LNG project operated
by UK-listed BG is likely to consume about 486PJ/yr at full
capacity. The 9mn t/yr Australia Pacific LNG project is likely
to use 514PJ/yr at full capacity and the 7.8mn t/yr Gladstone
LNG project operated by Australian independent Santos is
likely to consume 446PJ/yr.
All of the LNG projects’ gas supply is currently earmarked from the extensive coal-bed methane fields in
Queensland. Santos is also looking to supply its GLNG plant
from its considerable conventional and unconventional gas
interests in the Cooper basin.
Copyright © 2013 Argus Media Ltd
Drillsearch has a joint venture with BG to develop unconventional gas deposits in the Cooper basin. It is targeting
initial resource estimates from the drilling joint venture in
January 2015.
Drillsearch has focused its efforts in the Cooper basin on
oil and wet gas, which produces condensate and LPG.
Santos extends central Australia upstream venture
Santos and fellow Australian independent Central Petroleum
have agreed to amend their joint venture in an effort to
focus on the more prospective permits in central Australia’s
Amadeus basin and reduce their efforts in the Pedirka basin.
The A$150mn ($140mn) joint venture will give priority
to the southern Amadeus, which will result in an additional
300km of seismic surveys to the current 1,000km of 2D
seismic earmarked for the southern Amadeus. This follows a
decision by Santos and Central not to proceed as a joint venture in the Pedirka basin of central Australia, Central said.
The Wiso basin, which is to the north of the Amadeus
basin in the Northern Territory, will become a priority for
the venture following the review of existing and recently
acquired data, Central said.
Santos initially agreed in 2012 to fund exploration by investing an initial A$30mn, with an option to invest a further
A$60mn in each of a second and third stage. This will give
Santos the rights to up to 70pc of the permits by the third
stage. Santos will also take over operatorship during the
exploration and potential development phases. The move
to stage two will see Santos increase its stake in six permits
under the joint venture to 40pc from 25pc under stage one,
Central said.
Santos already has an interest in the Amadeus basin with
a 48pc stake in the Mereenie oil and gas project.
The Amadeus basin is more than 300km northwest of
Santos' interests in the Cooper basin, where it has produced
conventional gas for more than 40 years. It is exploring for
shale gas in the Cooper basin to provide additional supply for its two-train 7.8mn t/yr Gladstone LNG project in
Queensland.
Origin sees higher 2Q gas sales
Australian upstream and utility group Origin Energy saw
its gas sales volume increase to 30.3PJ (809.12mn m³) in
the April-June quarter compared with 28.6PJ for the same
period a year earlier.
The higher sales volume reflects higher production from
its share of output from the coal-bed methane gas fields in
Queensland that are part of the 9mn t/yr Australia Pacific
LNG (APLNG) venture, as well as higher output from its share
of output from the Otway basin offshore Victoria.
Origin’s share of output from its 37.5pc stake in APLNG
Page 13 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
was 12PJ in the April-June quarter, which was up from the
10.6PJ in the same period a year earlier and up from the
11.2PJ in the January-March quarter, according to the company’s latest production report.
Origin’s share of APLNG output was 46.3PJ in the 2013-14
fiscal year ending 30 June compared with 41.7PJ in 2012-13.
This implies that the APLNG venture produced 32PJ during
April-June and 85.33PJ for 2013-14
The average gas price that Origin received for the AprilJune quarter was A$4.29/GJ ($4.30mn Btu) compared with
A$4.04/GJ in the same period in 2013 and down from the
A$4.35/GJ for January-March.
AUD/GJ
Argus Victoria Index vs Wallumbilla Index
xxxxxxx
AVX - Victoria
4.50
AWX - Wallumbilla
4.00
3.50
3.00
2.50
2.00
1.50
30 May 14
20 Jun 14
11 Jul 14
1 Aug 14
Australia data
Daily eastern Australian pipeline flow rates
Pipelines/injection points
TJ
Capacity
TJ/d
25 Jul
26 Jul
27 Jul
28 Jul
29 Jul
30 Jul
31 Jul
Victoria
Lang Lang (BassGas) Gas Plant
Longford Gas Plant
70.0
40.0
39.0
40.0
40.0
40.0
40.0
39.0
1145.0
940.0
727.0
686.0
796.0
733.0
649.0
754.0
Orbost Gas Plant
100.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Iona Underground Gas Storage (Port Campbell)
570.0
56.0
70.9
81.8
56.8
82.8
57.0
73.7
Minerva Gas Plant (Port Campbell)
81.0
76.3
81.3
71.3
71.3
71.3
60.8
76.3
Otway Gas Plant (Port Campbell)
203.0
161.0
161.0
161.0
161.0
161.0
161.0
161.0
Dandenong LNG Storage
158.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
NSW-Victoria Interconnect (Culcairn)
120.0
9.4
-6.9
2.9
-18.1
-28.2
-6.8
-28.0
Longford to Melbourne Pipeline (LMP)
1030.0
677.2
564.7
535.1
607.6
583.0
510.2
624.6
166.9
South West Pipeline (SWP)
353.0
96.6
166.5
212.0
153.1
168.3
138.3
SEA Gas Pipeline
310.0
153.0
131.2
74.2
99.6
87.9
83.9
93.2
SEA Gas Pipeline (Adelaide zone)
310.0
133.0
109.7
65.9
91.0
78.8
75.0
84.2
Tasmania Gas Pipeline (TGP)
129.0
13.8
11.7
11.6
15.0
18.5
18.7
17.6
Eastern Gas Pipeline (EGP) (Canberra zone)
289.0
25.7
24.0
28.1
29.6
29.0
23.9
25.4
Eastern Gas Pipeline (EGP) (Sydney zone)
289.0
129.1
74.6
80.1
108.3
84.2
99.5
121.5
Eastern Gas Pipeline (EGP)
289.0
236.1
165.2
175.7
205.9
173.5
184.2
187.8
Queensland
Roma to Brisbane Pipeline (RBP)
233.0
117.8
109.2
111.9
161.2
177.3
202.2
179.9
Queensland Gas Pipeline (QGP) (Roma to Gladstone)
145.0
133.7
134.7
133.4
129.4
122.8
128.2
133.4
Carpentaria Pipeline (CGP) (Ballera to Mt Isa)
119.0
66.1
69.9
71.0
70.9
61.7
69.5
67.6
South West Queensland Pipeline (SWQP)
384.0
81.6
70.0
78.5
82.4
99.4
93.3
80.7
South West Queensland Pipeline (SWQP) (Moomba zone)
384.0
140.6
160.1
137.3
122.1
151.6
126.6
125.4
Kenya Gas Plant (Roma)
168.0
138.2
137.0
130.2
153.7
146.7
146.1
161.1
Talinga Gas Plant (Roma)
140.0
70.7
70.3
63.1
0.0
na
69.8
69.7
Ballera Gas Plant
150.0
35.2
0.0
45.8
38.8
14.2
11.0
2.8
South Australia
Moomba Gas Plant
430.0
261.2
264.2
252.5
260.3
252.7
254.9
252.7
Moomba to Sydney Pipeline System (MSP)
289.0
216.7
239.3
220.1
266.5
267.5
222.2
208.4
Moomba to Adelaide Pipeline System (MAP)
241.0
146.8
149.0
129.7
na
131.7
125.6
147.8
Moomba to Sydney Pipeline System (Canberra)
289.0
17.2
20.6
15.1
21.8
9.2
10.6
7.8
- Australian National Gas Market Bulletin Board
Copyright © 2013 Argus Media Ltd
Page 14 of 17
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
competing fuels in asia and power market indicators
S/mn Btu
Japan: Fuel oil vs LNG
18.5
18.0
17.5
17.0
16.5
16.0
15.5
15.0
14.5
14.0
13.5
13.0
12.5
12.0
11.5
11.0
10.5
10.0
6 May 14
ANEA front half month
Fuel oil LSWR V-500 Indonesia inc freight
2.95
2.90
12.0
2.85
11.0
5 Jun 14
3 Jul 14
1 Aug 14
$/mn Btu
ANEA™ front half month
Minas prompt inc freight
Dubai front month inc freight
16.0
14.0
16.0
13.0
14.0
12.0
12.0
11.0
3 Jul 14
1 Aug 14
$/mn Btu
India: Naptha vs LNG
5 Jun 14
3 Jul 14
ANEA™ front half month (LHS)
Fuel oil HS 180cst South Korea del (LHS)
Coal del Indonesia - South Korea 5,800 kcal (RHS)
10.0
6 May 14
25
3.60
3.50
3.40
3.30
3.20
5 Jun 14
3 Jul 14
3.10
1 Aug 14
$/mn Btu
India: Fuel oil, gasoil vs LNG
Argus India LNG front half month
Naphtha LR1 Mideast Gulf fob
2.75
1 Aug 14
$/mn Btu
South Korea: Fuel oil, coal vs LNG
18.0
5 Jun 14
2.80
10.0
6 May 14
15.0
22
3.00
13.0
20.0
10.0
6 May 14
Argus India LNG front half month (LHS)
Coal del Indonesia - India 4,200 kcal (RHS)
14.0
Japan:Crude vs LNG
22.0
$/mn Btu
India: Coal vs LNG
Argus LNG India front half month
Fuel oil HS 180cst Mideast Gulf inc freight
Gasoil 0.05% Mideast Gulf inc freight
20
18
20
16
15
14
12
10
7 May 14
5 Jun 14
Copyright © 2014 Argus Media Ltd
3 Jul 14
1 Aug 14
10
6 May 14
Page 15 of 17
5 Jun 14
3 Jul 14
1 Aug 14
Argus LNG Daily
Issue 14-150 Friday 1 August 2014
Power market indicators: breakeven gas prices for generation
$/mn Btu
Europe: Front month base load
Spain
13
UK
50
12
$/mn Btu
Latin America
Turkey
Brazil wholesale clearing price
Argentina MEM monthly average
40
11
10
30
9
20
8
10
7
19 Jun 14
3 Jul 14
17 Jul 14
31 Jul 14
0
Apr 12
Oct 12
Apr 13
Oct 13
Apr 14
Monthly lng import volumes
mn m³ LNG
Japan historic receipts
25
mn m³ LNG
China historic receipts
7
6
20
5
15
4
3
10
2
5
1
0
Nov 11
May 12
Nov 12
May 13
Nov 13
May 14
mn m³ LNG
South Korea historic receipts
12
0
Nov 11
May 12
Nov 12
May 13
Nov 13
May 14
mn m³ LNG
Spain historic receipts
4
10
3
8
6
2
4
1
2
0
Nov 11
May 12
Nov 12
Copyright © 2014 Argus Media Ltd
May 13
Nov 13
May 14
0
Oct 11
Page 16 of 17
Apr 12
Oct 12
Apr 13
Oct 13
Apr 14
Argus LNG Daily
Issue 14-150 Friday 1 August 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
20
20
18
15
16
10
14
5
12
0
10 Feb 14
$/mn Btu
USGC diesel vs LNG
4 Apr 14
5 Jun 14
31 Jul 14
$/bl
Ice brent front month
120
10
2 May 14
3 Jun 14
1 Jul 14
31 Jul 14
$/mn Btu
US Nymex
4.7
4.6
4.5
4.4
115
4.3
4.2
4.1
110
4.0
3.9
3.8
105
19 Jun 14
3 Jul 14
17 Jul 14
31 Jul 14
3.7
Sep 14
4Q 2014
2Q 2016
4Q 2017
2Q 2019
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illuminating the markets
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