BMI Vietnam Oil and Gas Report Q2 2014
BMI Vietnam Oil and Gas Report Q2 2014
BMI Vietnam Oil and Gas Report Q2 2014
www.businessmonitor.com
VIETNAM
OIL & GAS REPORT
INCLUDES 10-YEAR FORECASTS TO 2023
ISSN 1748-4375
Published by:Business Monitor International
DISCLAIMER
All information contained in this publication has been researched and compiled from sources believed to be accurate and reliable at the time of
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International accepts no liability whatsoever for any loss or damage resulting from errors, inaccuracies or omissions affecting any part of the
publication. All information is provided without warranty, and Business Monitor International makes no representation of warranty of any kind as
to the accuracy or completeness of any information hereto contained.
CONTENTS
BMI Industry View ............................................................................................................... 7
SWOT .................................................................................................................................... 9
Industry Forecast .............................................................................................................. 10
Table: Vietnam - Upstream Projects Database . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
43
43
43
43
45
46
47
50
50
52
52
Page 4
62
68
71
74
77
Page 5
Page 6
The main trends and developments for Vietnam's oil and gas sector are:
Total crude oil and liquids output will rise in the short term as new fields are brought online or are
ramped up to peak production levels. This could push production up from an estimate of 377,450 barrels
per day (b/d) in 2013 to 426,170b/d by 2016. However, this spell will end in 2017 unless further fields
are developed. BMI therefore expects production to decline from its 2016 peak to 373,560b/d by 2023.
Economic growth - expected to average at 6.7% over our 10-year forecast period to 2023 - will continue
to drive oil and gas consumption in Vietnam higher over the next decade. However, BMI's Country Risk
team holds the view that Vietnam's costly welfare subsidies will need to be gradually withdrawn as part
of the government's broader efforts to fix its fiscal imbalances and as such, we expect further price hikes
to come. This has led us to moderate our forecasts for Vietnam's oil consumption growth rate. We expect
total refined oil products consumption (previously referred to as total oil consumption) to rise at a slower
rate from an estimate of 389,160b/d in 2013 to 459,970/d in 2018 and 533,230b/d by 2023.
BMI estimates gas production will rise from an estimated 12.04bn cubic metres (bcm) in 2013 to
14.06bcm by 2018. However, we flag Chevron's exit from the major Block B project as indication of the
ongoing challenges facing investors in the country's gas sector. Although several companies have
expressed interest in the project, unless Vietnam can offer more attractive gas pricing terms, progress on
the block's development may be stilted. Gas demand will outstrip supply from 2015, with up to 0.7bcm of
net imports expected in that year. By 2023, net imports of gas could hit as much as 5.8bcm, all in the
form of liquefied natural gas (LNG).
Oil and gas reserves could rise if new exploration gathers pace. However, ongoing risks from vigorous
Chinese opposition to drilling in the disputed South China Sea could delay exploration. Therefore, for
2014 we have kept our oil reserves forecasts unchanged at 4.4bn barrels (bbl). However, Vietnam could
still find it difficult to reverse a longer-term decline in reserves as production ramps up to meet rising
domestic needs faster than discoveries are made to replace reserves. By end-2023, we expect proven oil
reserves to have fallen to 4.2bn barrels (bbl).
Rising interest in gas exploration and the number of encouraging finds to date suggests that in the shortto medium-term Vietnam's gas reserves are poised for an increase. We estimate that gas reserves will
continue to rise from 699bcm at the start of 2013 to about 702.4bcm in 2017. It could start dipping
towards the end of our forecast period to 616.5bcm, though we acknowledge significant upside risks from
further offshore and unconventional exploration.
Vietnam's refining production is set for a rise from the construction of two newbuild refineries - Nghi
Son and Vung Ro. Its refining capacity could increase from 140,000b/d in 2013 to 450,000b/d by 2018,
rising further still to 500,700b/d by the end of our forecast period when these refineries fully enter
operation. There is significant upside risk to this forecast, if four other proposed projects are brought into
fruition.
Page 7
Vietnam's refinery developments will preserve valuable light sweet domestic crudes for export, while
allowing for the processing of cheaper heavier foreign grades for domestic consumption.
At the time of writing we assumed an OPEC basket oil price for 2014 of US$101.80 per barrel (bbl), falling
to US$100/bbl in 2015. Global GDP in 2014 is forecast at 3.1%, up from an assumed 2.6% in 2012. For
2015, growth is estimated at 3.3%.
Page 8
SWOT
Vietnam Oil And Gas SWOT
Strengths
Weaknesses
Growing market.
Oil production set for longer-term decline towards the tail-end of our forecast period
without big discoveries.
Room for improvement for support services. Prevalence of counterfeit and low quality
fuel products in the retail sector.
Opportunities
Threats
Tension with China over territory in the South China Sea makes exploration in the
region more difficult, particularly for companies looking to develop Chinese assets. It
will compromise the country's long-term exploration potential.
Efforts to boost production of oil and gas may push regulators to threaten foreign oil
companies with production sharing contract (PSC) revisions and cancellations unless
they increase output.
Page 9
Industry Forecast
Table: Vietnam - Upstream Projects Database
Name
Field Name
Companies
Type of
Project
Status
Chim Sao
Chim Sao
Oil and
gas
Producing
25,000
0.256 Offshore
Lac Da
Nau
Lac Da Nau
Oil
Discovery
na
na Offshore
Ca Ngu
Vang
Ca Ngu Vang
Oil and
gas
Producing
20,000
11 Offshore
Dai Hung
Dai Hung
Oil
Producing
11,600
na Offshore
White
Tiger
Bach Ho
Vietsovpetro (PetroVietnam,
Zarubezhneft)
Oil
Producing
170,000
na Offshore
Cuu Long
(Block
15-1)
Development
(Ongoing)
66,000
0.460+ Offshore
Block
15-2/01
Development
35,000
na Onshore
Dua
Dua
Development
10,000
na Offshore
Vietnam
16-1
Phase II
Ngna O, Voi
Trang, Voi
Vang
Oil and
gas
Producing
40,000
0.307 Offshore
Block 9-2
Oil and
gas
Producing
7,000
0.204 Offshore
Oil and
gas
Development
(EOR)
16,200
na Offshore
Gas
Producing
na
2 Offshore
Gas
Producing
na
1.61 Offshore
Development
10,000
na Offshore
Development
10,000
na Offshore
Con Son
JOC
Gau Chua,
Con Son Joint Operating
Gau Ngua, Ca Company - Petronas,
Cho
PetroVietnam
Oil
Page 10
Name
Field Name
Companies
Type of
Project
Status
Lam Son
JOC
Thang Long,
Dong Do, Ho
Xam South
Oil
Development
15,000
na Offshore
HST/HSD
Oil
Development
15,000
na Offshore
Oil
Producing
25,000
na Offshore
na
na Offshore
Petrovietnam PVEP
Block B
Block B
Planned
NB * = operator; na = not available. Source: Company data, Reuters, Bloomberg, Oil & Gas Journal, BMI
2012
2013e
2014f
2015f
2016f
2017f
4.4
4.4
4.4
4.4
4.4
4.4
4,400.0
4,400.0
4,417.7
4,419.8
4,418.6
4,408.7
633.3
0.0
0.4
0.0
0.0
-0.2
33.6
31.9
30.1
29.0
28.4
28.6
0.7
0.7
0.7
0.7
0.7
0.7
699.4
699.4
687.0
693.9
695.5
702.4
263.2
0.0
-1.8
1.0
0.2
1.0
75.2
58.1
56.1
53.0
51.8
53.9
523.8
589.4
617.5
647.0
662.3
652.3
14.7
12.5
4.8
4.8
2.4
-1.5
20.1
21.5
21.8
22.4
22.8
22.5
16.2
7.0
1.5
2.9
1.8
-1.6
536.2
596.6
611.9
652.2
678.2
692.9
10.6
11.3
2.6
6.6
4.0
2.2
22.6
23.6
23.8
24.8
25.3
25.4
Page 11
Vietnam Proven Oil & Gas Reserves And Total Petroleum Data, 2012-2017 - Continued
2012
2013e
2014f
2015f
2016f
2017f
11.9
4.4
0.6
4.5
2.1
0.4
-12.5
-7.2
5.6
-5.2
-15.8
-40.6
-56.1
-41.9
-176.9
-193.1
205.7
156.0
-1.5
-1.1
-0.9
-1.3
-1.4
-1.9
-24.5
-25.2
-19.7
44.8
7.0
32.7
-0.6
-0.4
-0.3
-0.6
-0.6
-0.9
-1.2
-0.8
-0.6
-1.1
-1.2
-1.8
Table: Vietnam Proven Oil & Gas Reserves And Total Petroleum Data, 2018-2023
2018f
2019f
2020f
2021f
2022f
2023f
4.4
4.4
4.3
4.2
4.2
4.2
4,410.5
4,386.3
4,325.9
4,249.6
4,247.7
4,175.7
0.0
-0.5
-1.4
-1.8
0.0
-1.7
28.9
29.5
29.9
30.2
31.2
30.6
0.7
0.7
0.7
0.7
0.6
0.6
696.2
688.2
669.7
654.2
631.6
616.5
-0.9
-1.1
-2.7
-2.3
-3.5
-2.4
49.5
43.4
40.8
40.3
39.8
38.8
665.2
684.9
684.4
670.1
652.1
652.1
2.0
3.0
-0.1
-2.1
-2.7
0.0
22.8
23.5
23.5
23.0
22.4
22.6
1.5
3.0
0.0
-2.0
-2.5
0.8
745.3
798.6
842.6
873.4
886.3
901.9
7.6
7.2
5.5
3.7
1.5
1.8
Page 12
Vietnam Proven Oil & Gas Reserves And Total Petroleum Data, 2018-2023 - Continued
2018f
2019f
2020f
2021f
2022f
2023f
26.4
28.0
29.4
30.5
29.8
31.8
3.7
6.3
5.0
3.5
-2.2
6.9
-80.1
-113.7
-158.3
-203.3
-234.2
-249.7
97.5
41.9
39.2
28.5
15.2
6.6
-2.5
-3.5
-4.8
-6.3
-7.4
-8.0
33.3
37.3
39.7
30.6
17.4
8.2
-1.3
-1.8
-2.5
-3.3
-3.9
-4.2
-2.5
-3.6
-5.0
-6.6
-7.7
-8.3
The bulk of Vietnam's oil and gas reserves are located offshore in the Cuu Long and Nam Con Son basins.
The EIA has dramatically revised its estimates of proven oil reserves in Vietnam, from 600mn barrels
(bbl) at end-2011 to 4.4bn bbl at end-2012, and gas reserves from 195.6bn cubic metre (bcm) in end-2011 to
699.43bcm in end-2012. PetroVietnam expects to find up to 110mn barrels of oil equivalent (boe) between
2011 and 2015, with partner companies such as Soco International and Premier Oil set to make useful
contributions through recent oil finds.
Ongoing Exploration
Santos: The Australian company has a 65% operated interest in shallow water Block 13-03 offshore in
the Nam Con Son Basin. Following the acquisition of seismic survey data in 2012, Santos is planning to
spud an exploration well in 2014, testing the Hon Khoai oil prospect. The well is targeting mean
prospective resources of between 50 and 100 barrels of oil equivalent (boe). The company also has a 50%
operated interest in Block 123 in the Phu Khanh Basin. Following a non-commercial oil discovery from
its first exploration well in 2011, the company has completed a 564 km2 3D seismic survey and is
looking to spud a second exploration well in 2014.
Murphy Oil: The US independent has taken a 20% working interest in Santos'Block 13-03. This is in
addition to the 60% stake it has in Block 11-2, which it is currently reviewing seismic data for with an
eye to drill in early 2015. It is also looking to conduct a seismic survey for deepwater blocks 144 and 145
in 2014. Pan Pacific Petroleum: Its exploration campaign in Block 07-03 has yielded results from a
discovery called Red Emperor. Flow testing was conducted in the CRD-3X appraisal well and returned a
Page 13
flow rate of around 8,000b/d. The operator, Talisman, is currently assessing the commercial viability of
the project and progression to a detailed front end engineering design phase is expected by Q414, pending
results of the assessment. A further exploration well was spudded in January 2014, to evaluate the
resource potential of the Silver Sillago prospect, located 55km to the west of Ca Rong Do and sharing
similar geologic characteristics; a discovery here would add further upside to the block's prospectivity.
Talisman: The Canadian firm is planning to drill two key exploration wells in 2014, in Blocks 135 and
136 in the Nam Con Son basin. The first, in Block 136, is targeting an extension of the Ca Rong Do
prospect in Block 07-03; the second prospect, Vung May, straddles both Blocks 135 and 136.
Recent discoveries in Vietnam will likely help support current oil reserves levels. In July 2012,
Vietsovpetro announced that it had discovered a new source of oil at the Tho Trang (White Hare) field,
which is located in Block 09-1 north west of Vietnam's largest oil field Bach Ho. Vietsovpetro revealed that
the well THT-1X flowed 1,690 barrels of oil per day (b/d). Further drilling at four other potential sites at the
well could push this figure higher. A further well THT-2X was to be spudded to enable the VietnameseRussian joint venture (JV) to determine a development plan for the field. In January 2013, the joint venture
(JV) also targeted drilling at Block 09-3, where the Bach Ho field lies, and in Block 04-3. Perenco, the
French company which had acquired ConocoPhillips' assets in Vietnam, has also found exploration success
at well SV-6X in Block 15-1 in the Cuu Long Basin. Drill stem testing (DST) has seen the well flow over
10,000b/d and the firm plans to fast-track its development. This will add to Vietnam's proven oil reserves
when development is completed (targeted for 2014).
Another massive discovery near an existing production site is Soco International's TGT-10XST1 well in the
producing Te Giac Trang (TGT) field. The independent announced in October 2013 that the well flowed
more than 27,000boe/d, with resource estimate of 150-200mn bbl - or up to 4% of its existing oil reserves.
These additions are a positive sign and will help Vietnam maintain its current level of oil reserves of about
4.4bn bbl through to 2018. However, Vietnam could still find it difficult to reverse a longer-term decline in
reserves as production ramps up to meet rising domestic needs faster than discoveries are made to replace
reserves. By end-2023, we expect proven oil reserves to have fallen to 4.2bn bbl.
Gas Reserves
Gas exploration, particularly in offshore northern basins, is still in its early stages. An initial appraisal of
new discoveries in the Phu Khanh and Song Hong basins points to potentially significant gas reserves
growth. ExxonMobil's Phu Khanh find (Ca Voi Xanh 2X, block 118) could be the most promising to date.
The third well, Ca Voi Xanh-3X drilled in Q212, has also hit hydrocarbons, though the total size of the
discovery has yet to be made public. In February 2014, ExxonMobil announced that they had contracted a
Page 14
semi-submersible rig to begin appraisal drilling there. The discovery is another indication of the region's
resource potential following previous discoveries by Premier Oil, Total and Petronas.
Rising interest in gas exploration and the number of encouraging finds to date suggests that in the short- to
medium-term Vietnam's gas reserves are poised for an increase as companies develop gas resources and
book them as reserves.
A Japanese consortium consisting of Idemitsu, JX Nippon and Inpex confirmed a gas discovery made in
Blocks 05-1b and 05-1c in the Nam Con Son basin, and the find was backed by drill stem tests that
determined 'accumulations of gas and condensate', according to the official statement. The venture partners
will further appraise the well to evaluate its reserves potential and to identify other targets in the blocks.
These blocks lie north of Gazprom's blocks 05-2 and 05-3, which contain the Moc Tinh and Hai Thach gas
fields, which recorded first gas flow in August 2013.
Italian oil major Eni has also been active in offshore exploration, after farming into Block 105 in the Song
Hong basin and Block 120 in the Phu Khanh basin in the Gulf of Tonkin, in July 2012. However, in
December 2013, Eni's JV partner Kris Energy announced the completion of drilling and testing at first its
first exploration well in Block 120, Cua Lo-1. The well had been plugged and abandoned, after
encountering non-commercial volumes of oil and gas. In January 2014, an announcement was made that the
Ca Ngu-1 well, the first exploration well in Block 105, had also been plugged and abandoned; this time due
to poor deliverability and high carbon dioxide content. However, the company says it has identified other
oil and gas prospects within the block, and is looking towards further exploration Eni also has an interest in
Block 114, which is also located in the Song Hong basin and is estimated to hold 28bcm of gas.
We estimate that gas reserves will continue to rise to about 702.4bcm in 2017. It could start dipping towards
the end of our forecast period to 631.6bcm in 2023, though we acknowledge significant upside risks.
Methane Hydrates
Upside potential rests in Vietnam's unconventional potential, which the country is starting to look into.
Following Japan's methane hydrates breakthrough in March 2013, Vietnam has joined China in accelerating
efforts to search methane hydrates in the South China Sea. Vu Truong Son, director of the Centre of
Geology and Sea Mineral Resources at Vietnam's Ministry of Natural Resources, is optimistic that there are
'adequate conditions' for methane hydrates in its claimed portion of the South China Sea. Basins with
potential include Song Hong, Phu Khanh, Nam Con Son, Hoang Sa and Truong Sa. According to the US
Page 15
Geological Survey, the Vietnamese portion of the South China Sea is fifth in Asia in terms of methane
hydrates potential.
While methane hydrates exploration are in a very early stage and will not yield commercial results within
our forecast period, a closer look at its tight oil and gas resources could. In February 2013, Eni signed a
memorandum of understanding (MoU) with PetroVietnam to explore the country's coal-bed methane and
shale oil potential. Details of this collaboration are scarce, but this could yield results within the decade
given that technology and understanding of these are more advanced than that in methane hydrates.
A major downside risk to our forecasts comes from Vietnam's ongoing feud with China over territorial
rights to the South China Sea, parts of which Vietnam deems as the Vietnamese East Sea. Chinese
opposition to exploration in disputed areas of the South China Sea will also limit Vietnam's long-term
reserves growth.
The two nations have been at loggerheads in recent years over maritime borders and in May 2011 the
dispute actually interrupted exploration when Chinese ships allegedly entered Vietnamese waters. China's
June 2012 offshore licensing round has inflamed the situation further. Vietnamese officials allege that a
number of the blocks on offer are within Vietnamese territory. In December 2012, China flatly told Vietnam
to stop unilateral oil exploration in the contested areas in the South China Sea. China could similarly choose
to assert its dominance in Vietnam as it had with the Philippines; the Philippines' offshore exploration in
contested waters had resulted in the sending of naval ships by China in order to coerce its smaller
neighbour.
We have already taken this into account in our cautious forecasts of the country's oil and gas reserves, but
also see the risk that an intensification of this dispute will present further downside risks, particularly for oil.
We could therefore see the risk of increasing Chinese intervention which could in turn disrupt Vietnam's
upstream aspirations.
Page 16
2012
2013e
2014f
2015f
2016f
2017f
359.1
377.4
401.9
417.1
426.2
422.9
12.5
5.1
6.5
3.8
2.2
-0.8
131.1
137.8
146.7
152.2
155.6
154.4
14.4
14.6
14.9
15.2
15.4
15.0
14.6
1.7
2.3
2.0
1.2
-2.8
6.6
6.9
7.3
7.6
7.8
7.7
13.1
13.8
14.7
15.2
15.6
15.4
19.7
20.7
22.0
22.8
23.3
23.2
226.9
244.6
268.5
283.4
252.3
162.1
20.9
7.8
9.7
5.6
-11.0
-35.8
9.1
9.5
10.0
10.3
9.1
5.7
23.2
4.3
5.4
3.7
-11.8
-37.0
4.1
4.5
4.9
5.2
4.6
3.0
8.3
8.9
9.8
10.3
9.2
5.9
12.4
13.4
14.7
15.5
13.8
8.9
Page 17
2018f
2019f
2020f
2021f
2022f
2023f
418.0
406.9
396.8
385.2
373.6
373.6
-1.1
-2.7
-2.5
-2.9
-3.0
0.0
152.6
148.5
144.8
140.6
136.3
136.3
14.6
14.3
13.9
13.5
13.1
13.1
-2.2
-2.7
-2.5
-2.9
-3.0
0.0
7.6
7.4
7.2
7.0
6.8
6.8
15.3
14.9
14.5
14.1
13.6
13.6
22.9
22.3
21.7
21.1
20.5
20.5
26.9
-43.0
-75.5
-83.4 -260.0
75.7
16.7
14.3
0.9
-1.5
-2.6
-3.1
-3.5
-3.6
-83.6 -260.0
75.7
16.7
14.3
0.9
0.9
0.5
-0.8
-1.4
-1.6
-1.8
-1.9
1.0
-1.6
-2.8
-3.2
-3.7
-3.7
1.5
-2.4
-4.1
-4.8
-5.5
-5.6
Page 18
According to the EIA, total crude and liquids production in Vietnam rose rapidly to a peak of 403,000b/d in
2004, as the country's giant Bach Ho field drove output growth. Since then, volumes have gradually
declined as recovery rates from Bach Ho fell dramatically.
However, it appears that this trend has experienced a reverse. For 2012, state-owned PetroVietnam - which
has interests in all producing fields in Vietnam - reported that crude oil production rose 9.8% year-onyear (y-o-y) to 16.7mn tonnes, or about 335,370b/d. The EIA has an even higher estimate of 347,062b/d for
crude oil and lease condensate production. When natural gas liquids (NGL) and other liquids are taken into
account, total liquids output for Vietnam rose from 319,120b/d in 2011 to 359,606b/d in 2012. Fields
contributing to this growth include production from Perenco's Su Tu Trang field in Block 15-1, Premier
Oil's Chim Sao in Block 12W and a ramp up of production from Hoang Long Joint Operating Company's
Te Giac Trang in Block 16-01.
We anticipate that output will continue to rise in the short term as new fields are developed. Output growth
continued throughout 2013, and total liquids production reaching an estimated 377,450b/d. Talisman's Hai
Page 19
Su Trang and Hai Su Den (HST/HSD) development saw first production in May 2013 and Talisman and its
joint venture partner Petrovietnam are currently in the process of ramping-up output at the field, targeting
production of 15,000b/d. Gazprom's Moc Tinh and Hai thach gas condensate fields also began producing in
August 2013, with output set to peak in 2016 at 25,000b/d.
In 2014, oil production has been restored at the Chim Sao field. Production levels had been lowered in
August 2013 during repairs to the subsea gas export pipeline to reduce gas flaring; output fell from 25,500b/
d to 20,245b/d. In November 2013, Premier Oil announced that the rig for the Dua project was undergoing
final commissing and due to drill a minimum of three development wells at the Dua field, Block 12W, Nam
Con Son Basin. The wells are targeting a gross production rate of 8,000b/d in the first year, to be tied back
to the Chim Sao field. Lam Son Joint Operating Company's Thang Long and Dong Do fields were
scheduled to flow first oil in October 2013, but at the time of writing there was no indication that production
had started at either field. The development of Petronas' Gau Chua and Ca Cho discoveries in Blocks 10 and
11-1 has also reportedly been put on hold, pending a further evaluation of its economics. We have factored
this into our growth estimates for 2014 accordingly, and recognise that abandonment of the Gau Chua-Ca
Cho project would pose a minor downside risk to our mid- to long-term oil production forecast; potential
production for the two fields was projected at between 8,000 and 10,000b/d.
Cuu Long Joint Operating Company's Su Tu Nau field, Block 15-1, is moving forward in its
development. In December 2013, PetroVietnam Technical Services Corporation was a awarded the contract
to build and install two wellhead platforms at the field. Oil reserves are estimated at 120mn bbl, with a
targeted production rate of 50,000b/d. First oil is expected in Q414.
Several projects are also underway to boost production at existing fields. In November 2013, the
Vietnamese government granted a five year extension to the production sharing contract (PSC) for the Rang
Dong, Block 15-2, Cuu Long Basin, from 2020-2025. Operator JX Nippon Oil & Gas Exploration
Corporation (JX NOEX) is looking to initiate an enhanced oil recovery (EOR) campaign at the field. It the
same month, it was also reported that Hoang Long Joint Operating Company were looking to developing
a satellite project at the Te Chia Trang field, Block 16-1. Following positive results from DST at the
TGT-10X well, the company is looking to put a new platform in place, to tie into the project over the next
18-24 months. First oil is targeted for September 2015, pending government project approval.
Other projects that are expected to add to Vietnam's oil production between 2014 and 2016 are the
completion of Phase II of Block 16-01 and Petronas' Ham Rongproject, Blocks 102 and 106.
Page 20
While Vietnam's Indian summer with regard to production growth is encouraging, this spell could end in
2017 unless further fields are developed. Its flagship Bach Ho field is fast drying and maintaining recovery
rates is proving difficult for operator Vietsovpetro. New fields will struggle to mitigate this lost output
beyond 2017 even if new wells are drilled on the fringes of Bach Ho. BMI therefore expects production to
decline from its 2016 peak of 426,170b/d to 373,560b/d in 2023.
Consumption Hike
Total refined oil product consumption (previously referred to as oil consumption) came in at about
376,000b/d in 2012, according to the EIA, a lower y-o-y increase than in 2011. This could be partly due to
the effects of a 4.3% hike in fuel prices announced by Petrolimex, Vietnam's largest fuels importer and
distributor, on August 1 2012. Such price hikes come after the government enacted legislation, originally
passed in 2009, that allows fuel distributors more freedom to set sales prices independently. The move stops
well short of a full market liberalisation, but allows retailers to react more quickly to changes in global
prices in the form of price revisions.
In December 2013, the Ministry of Finance issued a permit allowing wholesalers to raise the prices of
gasoline, kerosene and diesel by VND584, VND384 and VND635 per litre respectively. This was the fifth
time fuel prices had been raised in 2013, alternating with six price decreases. The decision was taken in
response to the growing fiscal burden posed by the fuel subsidies that are on offer to market actors in
compensation for the low prices they are paid for their products. According to the Ministry of Finance, as of
December 2013, domestic retail prices for fuel were on average VND914-1,414 per litre cheaper than
international market prices.
However, BMI's Country Risk team holds the view that Vietnam's costly subsidies will need to be gradually
withdrawn as part of the government's broader efforts to fix its fiscal imbalances and as such, we expect
further price hikes to come, even if global crude prices were to stabilise at current levels.
Strong economic performance will continue to drive oil consumption in Vietnam over the decade. BMI's
latest macroeconomic forecasts currently point to average real GDP growth of 6.7% between 2013 and
2023. Although the Vietnamese power sector's demand for oil is expected to shrink over the decade, oil
inputs into the manufacturing sector and strong vehicle growth will more than compensate. Our Autos team
expects annual vehicle sales rates to more than double over the next five years, rising from 93,093 in 2013,
to 140,845 in 2018, with passenger cars making up a bulk of the domestic autos market. Greater use of oilfuelled vehicle will support consumption growth in one of the fastest growing emerging markets in the
Page 21
world. Nonetheless, we have tapered down our expectations for oil demand growth, as the transport sector
in particular could see a reduction in fuel demand in response to higher fuel prices that we expect as
subsidies wind down.
Thus, we expect total oil consumption to rise at a slower rate than our previous forecast from 389,200b/d in
2013 to 444,400b/d in 2017 and 533,200b/d by 2023. The impact of further price liberalisation - leading to
higher fuel prices and reducing the rate of demand growth - has already been accounted for in our forecasts.
Downside risks could come from increased fuel efficiency and a switch from oil to gas, particularly that in
the transport and manufacturing sector, though population growth and economic expansion will likely
negate some of these effects. Moreover, Vietnam's limited gas output and the lack of gas import facilities
will limit gas' gains over oil in the short-term.
2012 2013e
2014f
2015f
2016f
2017f
140.0
140.0
140.0
140.0
190.0
345.0
0.0
0.0
0.0
0.0
35.7
81.6
94.4
94.9
95.3
95.5
91.5
75.6
132.1
132.8
133.5
133.7
173.9
260.8
0.5
0.5
0.5
0.2
30.0
50.0
376.0
389.2
400.8
414.9
429.4
444.4
6.8
3.5
3.0
3.5
3.5
3.5
5.1
4.3
5.1
-9.1
-28.1
-10.6
-10.6
-10.9
-11.3
-10.0
-7.0
12.9
0.0
2.7
4.0
-11.3
-30.7
-4.7
-4.9
-5.2
-5.6
-5.0
-3.5
-9.5
-9.8
-10.4
-11.1
-9.9
-7.0
-14.2
-14.6
-15.6
-16.7
-14.9
-10.5
132.8
133.5
134.1
134.4
174.6
261.6
0.5
0.5
0.5
0.2
29.9
49.8
376.1
389.3
401.0
415.0
429.5
444.5
Page 22
2012 2013e
Refined Products Consumption (inc ethanol and non-conventional), %
change y-o-y
2014f
2015f
2016f
2017f
6.8
3.5
3.0
3.5
3.5
3.5
2018f
2019f
2020f
2021f
2022f
2023f
450.7
500.7
500.7
500.7
500.7
500.7
30.6
11.1
0.0
0.0
0.0
0.0
86.8
89.8
94.3
94.5
94.7
94.9
391.2
449.9
472.4
473.3
474.2
475.2
50.0
15.0
5.0
0.2
0.2
0.2
460.0
473.8
488.0
502.6
517.7
533.2
3.5
3.0
3.0
3.0
3.0
3.0
-68.8
-23.9
-15.6
-29.3
-43.5
-58.0
-62.5
-65.2
-34.6
87.6
48.2
33.6
-2.3
-0.5
-0.2
-0.7
-1.2
-1.8
-67.5
-77.2
-64.4
281.6
76.2
46.3
-1.1
-0.3
-0.1
-0.4
-0.6
-0.9
-2.3
-0.5
-0.2
-0.7
-1.3
-1.9
-3.4
-0.8
-0.3
-1.1
-1.9
-2.8
392.0
450.7
473.2
474.3
475.2
476.1
49.9
15.0
5.0
0.2
0.2
0.2
460.1
473.9
488.1
502.8
517.9
533.4
3.5
3.0
3.0
3.0
3.0
3.0
Page 23
Although PetroVietnam has put an expansion of Dung Quat's capacity to rest following an order from the
government, other projects will contribute to growth. A long-proposed refinery at Phu Yen has also been
given the green light to proceed by Vietnam's Prime Minister. Initially slated for a capacity of 4mn tonnes
per annum (mpta, or 80,360b/d), the Vung Ro refinery is now planned to process twice the amount at
160,720b/d. Construction of the plant began in 2013 and the project is scheduled for completion in 2018.
Another refinery project that has been proposed is PTT's Nhoi Hoi refinery in Binh Ding province. It is a
mega-refinery project designed to process 660,000b/d of crude oil. The Thai petrochemicals firm is still
conducting a feasibility study and if this goes well, the US$25-30bn mega facility could see construction
begin in 2016 and come online by 2020. While the local government of Binh Dinh is supportive of the Nhoi
Hoi project, PetroVietnam has filed a complaint against it on grounds that its location is too close to Dung
Quat and a proposed 200,800b/d Van Phuong plant. Other projects proposed include state-owned
PetroVietnam's 200,900b/d plant in Long Son (though it is still struggling to find partners).
Page 24
These recent developments have led us to revise our forecasts. Accounting for the additional capacity that
Nghi Son and Vung Ro will add to the Vietnamese market, we now project its refining capacity to increase
to 345,000b/d by 2017. By 2019, we expect this to reach 500,700b/d when both refineries hit their full
capacity.
This will put on toll on Vietnam's net crude oil exports, given rising domestic demand for crude to feed its
refineries. With crude oil output expected to trend downwards, growing refining capacity could see its net
exports of crude oil and other liquids fall from an estimate of 244,640b/d in 2013 to -101,630b/d by 2023.
In other words, the country is set to become a net crude oil importer by 2019 unless crude oil production
ramps up.
Meanwhile, the large scale of PTT's Nhoi Hoi refinery - which could make Vietnam into a net fuels
exporter if it does indeed materialise - makes it a risky investment in Vietnam's tightly regulated domestic
fuels market, and in a regional market where fuel exports are likely to face fierce competition. Hence, we
Page 25
will await clearer indications towards an FID on Nhoi Hoi before we will consider it in our forecasts.
However, we note that the prospects for Nhoi Hoi could pick up following an expression of interest in the
project by Russian petrochemical firm SamaraNefteOrgSintez (Sanors) in November 2013. Sanors chief
executive Igor Soglayev stated that the firm would need 'clear commitments of the involved governments'
before it would go ahead with investment.
2012 2013e
Dry Natural Gas Production, bcm
2014f
2015f
2016f
2017f
9.3
12.0
12.3
13.2
13.7
13.3
20.6
29.5
1.9
7.5
3.9
-2.7
22.8
25.2
-2.1
5.6
2.8
-4.7
2.0
2.6
2.6
2.8
2.9
2.9
4.0
5.2
5.3
5.6
5.9
5.7
6.0
7.7
7.9
8.5
8.8
8.6
100.0
100.0
100.0
100.0
100.0
93.3
9.3
12.0
12.3
13.2
13.7
14.3
20.6
29.5
1.9
7.5
3.9
4.2
5.1
6.3
6.2
6.6
6.7
6.9
22.8
25.2
-2.1
5.6
2.8
2.1
0.0
0.0
0.0
0.0
0.0
-1.0
0.0
0.0
0.0
0.0
0.0
-0.5
0.0
0.0
0.0
0.0
0.0
-0.2
0.0
0.0
0.0
0.0
0.0
-0.5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-1.0
0.0
0.0
0.0
0.0
0.0
1.0
0.0
0.0
0.0
0.0
0.0
-0.5
Page 26
2018f
2019f
2020f
2021f
2022f
2023f
12.8
12.4
11.9
11.5
11.1
10.8
-3.7
-3.6
-3.7
-3.4
-3.3
-3.2
-4.7
-3.6
-3.7
-3.4
-3.3
-3.2
2.7
2.6
2.6
2.5
2.4
2.3
5.5
5.3
5.1
4.9
4.8
4.6
8.2
7.9
7.7
7.4
7.1
6.9
90.9
90.1
81.4
72.5
67.7
64.8
14.1
13.7
14.6
15.8
16.4
16.6
-1.0
-2.8
6.6
8.4
3.6
1.1
6.7
6.6
7.0
7.6
7.8
7.9
-2.1
-2.8
6.6
8.4
3.6
1.1
-1.3
-1.4
-2.7
-4.4
-5.3
-5.8
35.7
5.3
100.0
60.0
21.9
10.3
-0.6
-0.6
-1.3
-2.1
-2.5
-2.8
34.3
5.3
100.0
60.0
21.9
10.3
-0.3
-0.3
-0.7
-1.1
-1.3
-1.5
-0.6
-0.7
-1.4
-2.2
-2.6
-2.9
0.0
0.0
0.0
0.0
0.0
0.0
35.7
5.3
100.0
60.0
21.9
10.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
34.3
5.3
100.0
60.0
21.9
10.3
-1.3
-1.4
-2.7
-4.4
-5.3
-5.8
35.7
5.3
100.0
60.0
21.9
10.3
1.0
1.0
1.0
1.0
1.0
1.0
2,012.0
-0.7
-1.4
-2.2
-2.7
-3.0
0.0
0.0
0.0
0.0
0.0
0.0
Page 27
2001-2023
A ramp-up in production from Lan Do and Perenco's Su Tu Den oil complexes is expected over the
forecast period and several new projects set to come online. They include:
Gazprom's Moc Tinh and Hai Thach fields in the Nam Con Son basin. Production was launched in
October 2013. Peak output is expected at 3bcm per year.
Vietsovpetro's Thien Ung and Mang Cau fields, also in the Nam Con Son basin. This will come online in
2015 if it goes according to plans.
However, we see output gains here largely offset by decline in some of Vietnam's other producing gas
fields, notably Tien Hai C, Lan Tay, Rong Doi/Rong Doi Tay and Bunga Orkid, as well as lower associated
gas production at Bach Ho and Rang Dong.
Hence, we expect gas output to marginally rise from 12bcm in 2013 to 12.8bcm in 2018, before falling to
10.8bcm towards the end of our forecast period.
Page 28
We highlight as well that there are significant upside risks to this forecast.
ExxonMobil's assets in the Phu Khanh basin, where two wells with gas shows were hit. Previously held
by BP, high hydrogen sulfide and carbon dioxide content had made production un-commercial. However,
growing research and development in the removal of carbon dioxide from gas wells could improve the
economics of development in the longer term and help bring this difficult gas source online.
Exploration by Eni in the Song Hong and Pku Khanh basins, both of which have known gas potential (see
section 'Oil and Gas Reserves'). Block B project in the Malay-Tho Chu basin. Chevron is reported to be
seeking a partner to buy all of its interest in the field (42.8%). If it comes on-stream, peak output of 5bcm
per year can be expected. Further upside potential could come from exploration of Vietnam's
unconventional resources. However, at this stage it is too early to tell if they can substantially boost the
volume of the country's gas output
Consumption Challenges
Supply Constraints
Distribution Of Imports And Domestic Supplies
In Gas Consumption Mix
The transport sector will also likely witness an increase in Compressed Natural Gas (CNG)-powered
vehicles. State-owned gas distributor PV Gas reports that enterprises in Ho Chi Minh City are 'actively
switch[ing] to using CNG-powered vehicles', prompted by process which are 'cheaper by 30%' than
gasoline, according to PV Gas. This includes 600 vehicles operated by PetroVietnam in Ho Chi Minh and
Page 29
the Ba Ria-Vung Tau province. The country also launched its first local CNG bus in April 2013, in addition
to the existing 30 imported CNG-based buses it already has.
This further supports a greater move towards CNG as a fuel in public transport. An additional 300 CNG
buses are expected by the transport department to serve Ho Chi Minh by April 2014. Gazprom and
Petrovietnam also signed an agreement in October 2013 for a joint venture project to use gas as a vehicle
fuel. This could see closer gas collaboration between both Russia and Vietnam.
This informs our bullish view of Vietnamese gas consumption growth, which we expect to increase from an
estimate of 12bcm in 2013 to 16.6bcm by 2023 - or an average increase of 7.5% per annum over our 10year forecast period. The higher rate of consumption to production growth also means that Vietnam's selfsufficiency in gas is expected to come to an end by 2015. A planned liquefied natural gas (LNG) import
facility, which has been slated for a 2015 start will supplement domestic supplies to meet the country's
needs (see sub-section 'LNG' below). However we expect the country's gas imports to increase from zero at
present to 5.5bcm by 2022.
We see the main impediment to consumption growth as a supply-driven one, which has in turn influenced
our forecasts. It appears that additional import facilities - in the form of a 1mn tonnes per annum (tpa) - the
equivalent of 1.38bcm - and 3mn tpa (4.14bcm) terminal will not come on-stream early enough or be
sufficient to sustain a double digit y-o-y gas consumption growth that Vietnam is capable of. Hence, growth
rate is expected to be erratic as a result of import infrastructure and domestic gas production constraints on
growth.
Our expectation of supply constraints to consumption growth assumes a 1mn tpa LNG import terminal to
come online in 2015 and a 3mn tpa facility to start operations in 2018. However, neither long-term supply
contracts nor plans for both LNG plants have been finalised and thus present significant downside risks to
our forecasts. On the other hand, a higher planned capacity for both terminals, if they can come into
operation soon enough, will present an upside. In addition, greater domestic gas production beyond our
current output forecasts will also help push consumption upwards.
LNG
LNG imports have been given priority status in Vietnam's 2016-2025 gas development plan, which was
unveiled in 2011. The first LNG regasification terminal is to be built in southern Vietnam, the second
terminal in the north and a third in central Vietnam.
Page 30
However, construction plans have been slow to progress. We have taken into account two facilities
currently under development by PetroVietnam subsidiary PV Gas. These include a 1mn tonnes per annum
(tpa) LNG import terminal along the Thi Vai river in southern Vietnam (Thi Vai LNG), expected to begin
operations in 2015, and a second terminal (Son My LNG) with a capacity of up to 3mn tpa set to start up
around 2018-2020 at Binh Thuan in north Vietnam. They account for our forecast for the beginning of LNG
imports into Vietnam from 2015, and a bump in import capacity from 2018.
Both LNG terminals are mainly targeted at the power sector. PV Gas also plans to expand the capacity of
Thi Vai to 6-10mn tpa (8.3-13.8bcm) after 2020, but we have yet to factor this into our forecasts until plans
are more concrete.
However, state-owned PV Gas has yet to sign any long-term supply contracts to secure gas for its planned
terminals. It has been in talks with Australia and Qatar. Parent company PetroVietnam has also been in talks
with Gazprom for 'deepening cooperation' in LNG marketing. It is in the midst of negotiating a long-term
supply contract with the Russian gas company, which would see PetroVietnam obtain gas from Gazprom's
Vladivostok terminal. Gazprom stated that a framework agreement could be signed before the end of 2013
at the time of writing. However, Vladivostok is not due to come on stream until 2018 at the very earliest.
Therefore, it is likely that PetroVietnam could source most of its gas via short-term contracts before this
date.
Revenues/Import Costs
In 2013, we expect Vietnam's net crude oil exports to have risen to about 244,600b/d from about 226,900b/d
in 2012. This is set to continue until 2015, until an expansion in Vietnam's refining capacity takes place.
This could see an increase in crude oil export revenue from US$9.1bn in 2012 to US$9.3bn in 2013. By
2018 and 2023, however, Vietnam could turn from a net crude oil exporter into a net crude oil importer,
when both the Nghi Son and Vung Ro refineries come online and increase refinery demand for crude oil by
about 360,000b/d. Crude oil exports could thus fall to around 28,900/d in 2018, and Vietnam could have to
import 101,600b/d of crude oil by 2023 at a cost of US$3.5bn.
This could be offset by a decrease in its refined oil products import requirement. Growing consumption
would see refined oil product imports initially rise from an estimate of 256,400b/d in 2013 to 281,100b/d in
2015, before falling to 68,800/d in 2018 and 58,000b/d by 2023. Its import bill for refined oil products
would also fall from US$11.1bn in 2013 to US$2.9bn in 2018 and US$2.4bn by 2023.
Page 31
Oil revenues are also highly dependent on price fluctuations; changes in crude oil prices will affect the
country's total import bill for oil and gas.
Page 32
The main themes arising from BMI's Oil & Gas Risk/Reward Ratings (RRRs) for Asia are:
High level of state involvement in the sector keeps industry scores low relative to other regions, as it
takes a toll on Country Rewards and Industry Risk scores, both of which assess different facets of the
level of state involvement and control over the sector.
Unsurprisingly, countries with large below-ground potential top the Upstream RRRs tables. However,
there are several countries with huge exploration potential that have underperformed. Indonesia is a case
in point, as increasing signs of state intervention have led to the deterioration of its operating
environment. This has in turn pushed down its Country Rewards and Risk scores, placing it in 11th
position in our upstream Risk/Reward rankings.
Interestingly, with the exception of Australia, it is the markets with poor Upstream Rewards such as
Japan, Hong Kong, South Korea and Singapore that show some of the highest scores in Industry Risks,
which has in turn lifted their final Upstream Risk/Reward scores. Nonetheless, poor below-ground
prospects leave them at the bottom of the regional table.
In the long term, we see room for Upstream Rewards to grow on the back of reserves and production
growth as unconventional exploration looks set to pick up.
For Singapore, Japan and South Korea, large downstream capacities combined with strong operating
environments have helped them maintain their high positions in our regional Downstream RRRs.
Nonetheless, these countries are gradually losing their advantage as they come under challenge from
emerging competitors, such as India and China, which have larger markets and newer plants. China, for
example, already ranks second in our downstream ratings table.
Although some of the world's fastest-growing downstream market demand is in Asia, fuel price
regulation and high energy dependency in many developing markets have pushed down scores for
Country Rewards and Risks. As a result, many countries such as Vietnam and Indonesia have
underperformed in our downstream rankings. The continuation of high crude oil prices and fuel subsidies
poses significant downside risks to the profitability of the downstream segment in many Asian
developing countries.
Page 33
Countries that top our overall RRRs perform relatively well in both upstream and downstream, though we
do highlight that Australia is at risk of losing its leading position in our ratings, as the gap with runner-up
China gradually narrows.
Rank
Australia
68.6
60.0
64.3
China
57.2
61.6
59.4
Vietnam
63.5
51.7
57.6
India
53.8
56.7
55.3
Japan
48.3
61.5
54.9
Thailand
54.1
54.4
54.3
Malaysia
56.5
50.1
53.3
61.8
44.7
53.2
Pakistan
55.7
49.7
52.7
Singapore
39.3
64.7
52.0
10
Philippines
52.7
50.8
51.8
11
South Korea
33.2
60.2
46.7
12
Indonesia
40.0
47.8
43.9
13
Hong Kong
35.8
52.1
43.9
14
Taiwan
16.9
36.5
26.7
15
Page 34
Vietnam remains in close second place in our Upstream RRRs thanks to its leading regional rewards score
arising from its good below-ground potential and its under-explored waters. Promising gas output growth
prospects arising from a number of encouraging finds to date, proven oil reserves, and a healthy level of
offshore industry activity maintains the country's leading position in Asia for Industry Rewards. Policy
continuity and above-average participation from private players in Vietnam's upstream segment for the
region also lend support. However, a poor performance on corruption and rule of law, and E&P in the
contested South China Sea, where many of these prospects lie, poses a significant downside risk to the longterm returns of venturing deeper into Vietnamese and Philippine waters.
Unconventional exploration and investment has helped China retain fourth place in the regional upstream
table, thanks to a second-best score in the region for upstream Industry Rewards. However, at the moment,
unconventional exploration in the country has been slow and could be complicated by its difficult
geology. China has a reasonable Country Rewards rating but its score in this category is mainly dragged
down by the significant role played by the state in the oil and gas sector. State ownership of upstream assets
remains a constraint to better performance.
Page 35
On the back of revisions in our production forecasts for Papua New Guinea (PNG), the country has recently
seen a steep increase in its Upstream Industry Rewards. The country's significant gas finds offshore, the
almost complete liquefied natural gas (LNG) terminal, underexplored gas-rich acreage and its strategic
location for exports to the Asian market have fed into its overall ratings, sending it four places higher to sit
third in our regional upstream table, slightly behind Vietnam.
State involvement in the upstream sector continues to weigh on the RRRs of some of the most resource-rich
countries. Although most oil and gas projects are licensed under the production sharing contract (PSC)
model, most of them involve high local content requirement and entitle national oil companies (NOCs) to
large shares in new projects. This regulatory framework has pulled down scores in India, Malaysia and
Indonesia in recent quarters, despite these countries' sizeable resource bases.
Page 36
For example, Malaysia performs increasingly well in terms of Upstream Industry Rewards, supported by a
favourable gas reserves to production ratio. However, its overall score is dragged down by its mediocre
Industry Risk score due to a continued large presence of state ownership of upstream assets. In addition, the
country's broader Country Risk environment remains only mildly attractive, with relatively low scores for
corruption and rule of law which undermine its overall performance.
Indonesia is another case in point, with mediocre scores for Country Risk and Rewards. A highly involved
government and contradictory policies present strong limitations to its upstream segment despite strong
below-ground potential. Creeping resource nationalism in past quarters is also a threat to Indonesia's
Industry Risk scores, as the increasingly intrusive government could introduce more restrictions to private
production and marketing activity, and as a growing domestic reservation requirement for oil and gas output
makes it less attractive than other countries in the region. Similarly, the state's low scores for corruption,
rule of law and infrastructure undermines its overall performance.
Although regulatory troubles are hindering India's short-term potential, we highlight that if they are
overcome, the country could see its Upstream RRRs scores improve. Indeed, India has gas potential, but
current production falls well short of the country's ultimate potential. In fact, the upward adjustment of
domestic gas prices to nearly double that of the previous level by April 2014 is a positive sign for the
country. Although prices of about US$8 per million British Thermal Unit (mnBTU) are still below
international levels, this will raise the incentive for investment into the country's deepwater and
unconventional resources. We therefore anticipate strong gas production growth to begin from 2016
onwards.
The country also appears to be moving ahead with a shale gas regulation. In September 2013, the Indian
government granted ONGC and Oil India the rights to explore for unconventional on the 176 existing
licences that are prospective for shale. While the new policy does not yet cover contracts for blocks
awarded to non-state explorer, another Cabinet approval should likely offer shale oil and gas blocks to nonstate explorers. This is in advance of a shale gas licensing round originally slated to be held in December
2013, but which will more likely occur in 2014, according to the Indian Oil Ministry. As a result, we could
see an improvement in India's upstream Country Rewards score next quarter, should the long-awaited
policy come through.
Page 37
Upstream
Industry
Rewards
Upstream
Country
Rewards
Upstream
Rewards
Upstream
Industry
Risks
Upstream
Country
Risks
Upstream
Risks
Upstream
R/R
Ratings
Rank
Australia
47.5
100.0
60.6
87.5
86.2
87.0
68.6
Vietnam
68.8
70.0
69.1
55.0
42.6
50.6
63.5
Papua New
Guinea
58.8
65.0
60.3
80.0
37.6
65.2
61.8
China
61.3
50.0
58.4
55.0
53.0
54.3
57.2
Malaysia
58.8
60.0
59.1
45.0
60.6
50.5
56.5
Pakistan
46.3
77.5
54.1
75.0
30.6
59.5
55.7
Thailand
38.8
72.5
47.2
80.0
51.7
70.1
54.1
India
56.3
47.5
54.1
50.0
59.5
53.3
53.8
Philippines
45.0
65.0
50.0
65.0
48.0
59.1
52.7
Japan
15.0
70.0
28.8
100.0
82.1
93.7
48.3
10
Indonesia
37.5
50.0
40.6
35.0
45.5
38.7
40.0
11
Singapore
6.3
50.0
17.2
100.0
73.6
90.8
39.3
12
Hong Kong
0.0
50.0
12.5
100.0
72.0
90.2
35.8
13
South
Korea
5.0
32.5
11.9
90.0
69.6
82.9
33.2
14
Taiwan
15.0
0.0
11.3
10.0
67.7
30.2
16.9
15
Average
37.3
57.3
42.3
68.5
58.7
65.1
49.2
Downstream Support
Singapore maintains its position at the top of our downstream charts, largely thanks to its top-of-the table
performance in Downstream Risks and improving performance in overall Downstream Rewards. As the oil
products trading hub of the region, supported by large and sophisticated refineries, the country is wellplaced to compete in the global fuels market thanks to its good physical trade and financial infrastructure
networks.
Other top performers include the region's traditional refining giants South Korea and Japan. Like Singapore,
a mature industry coupled with a stable operating environment has boosted their Downstream Risks scores
to seal their top places in the region's downstream segment. After conceding its third place to Japan last
quarter, Australia continued its downward trend by ending in fifth position behind South Korea. Domestic
Page 38
production is increasingly challenged by cheaper fuel imports from Asia and increasing crude feedstock
costs due to dwindling domestic supplies.
However, we highlight that these traditional leaders are under threat. With mega-refineries emerging in
India, China and in the Middle East, they are coming under intense pressure from new players cutting into
its traditional market share. This has been exacerbated by a weak global macroeconomic environment that is
tempering global demand for oil.
In terms of Downstream Rewards, these traditional refining giants are also increasingly eclipsed by
emerging markets. Thanks to their large and still-growing domestic market for oil and gas consumption,
countries such as India and China are leading the region in this respect. Domestic fuel price regulations,
which have artificially depressed prices and are affecting refining margins are holding back downstream
risk scores for these markets, which remain average for the region. However, they have made up for this
weakness with an active effort to develop a large refining sector that can not only meet the needs of the
domestic market, but also target the export market. Chinese government policies to upgrade fuel standards
Page 39
and a recent reform of its pricing mechanism - to more closely align with price changes in the global market
- have also increased opportunities for rewards.
Rising demand and limited domestic fuel supplies create opportunities in South East Asian countries.
However, state involvement in downstream pricing has hit risks and rewards in emerging markets such as
Indonesia, Vietnam and Malaysia despite an expected increase in domestic consumption. Indonesia is a case
in point, falling one place to 13th this quarter after a decline of three places in Q413. The fall in its
downstream Industry Rewards score comes as opportunities in the refining sector are limited by the
dominant role of the state and heavy state subsidies, despite the country's large domestic market.
Scores for these countries also remain average because there appears to be a growing risk of overcapacity in
the region. While early investment is likely to pay off, later entrants into these markets may find themselves
struggling not only because of oversupply in the domestic market, but also from tough competition in the
wider regional market. This could improve especially with growing inclinations towards relaxing price
Page 40
controls. Indonesia has made the politically difficult decision to raise fuel prices by cutting its subsidies.
Both Malaysia and Vietnam had also partially raised fuel prices in Q313.
We can see the difficulties of the downstream sector reflected in the downstream scores of the markets. The
table of our ratings below shows that the risks associated with operating in the downstream segment in
China for example are greater than the opportunities (shown by the lower score for risks than for rewards).
Similarly, Indonesia displays downstream risks which are almost equal to its low Downstream Rewards
ratings, which suggests a particularly high relative opportunity cost of operating in this market.
Page 41
Downstream
Industry
Rewards
Country
Rewards
Rewards
Industry
Risks
Country
Risks
Risks
R/R
Ratings
Rank
Singapore
51.1
56
52.3
100
84.1
93.6
64.7
China
65.6
63
64.9
45
66.8
53.7
61.6
Japan
42.2
72
49.7
100
72.5
89
61.5
South Korea
37.8
72
46.3
100
81.4
92.6
60.2
Australia
41.1
66
47.3
100
73.8
89.5
60
50
70
55
65
54
60.6
56.7
Thailand
44.4
60
48.3
75
59.3
68.7
54.4
Hong Kong
32.2
52
37.2
100
67
86.8
52.1
Vietnam
52.2
50
51.7
45
62
51.8
51.7
Philippines
37.8
63
44.1
70
61.1
66.5
50.8
10
Malaysia
48.9
46
48.2
45
69
54.6
50.1
11
Pakistan
44.4
56
47.3
65
40.1
55
49.7
12
Indonesia
44.4
56
47.3
45
55
49
47.8
13
32.2
56
38.2
75
37.3
59.9
44.7
14
Taiwan
34.4
34
34.3
20
73.9
41.6
36.5
15
Average
43.9
58.1
47.5
70
63.8
67.5
53.5
India
Page 42
Country Rewards: Also influencing Vietnam's good upstream position is its attractive country rewards
rating. The state has substantial ownership via PetroVietnam and licensing deals but the number of nonstate operators in the upstream segment is above average for the region, with direct access for IOCs better
than the regional norm.
Country Risks: Vietnam's broader Country Risks environment is its main weak point, with the country
achieving a score of 42.6 out of 100 in this category. Long-term policy continuity is its main strength, but it
is outweighed by significantly lower scores for corruption and rule of law, while a lack of physical
infrastructure provides further operational risks for private companies.
Downstream Scores
Vietnam is 11th in BMI's overall downstream ratings. At 47.5, it has an average score in the region for
Downstream Rewards - while it is a growing market, state bureaucracy can be a serious impediment to the
start-up of projects. Fuel price regulation also dims the rewards that the fast-growing Vietnamese economy
could have, especially when its market size is smaller than that of emerging India and China. We also warn
Page 43
that its relatively small market size may not warrant large newbuild refineries, as refined oil exports would
face a tough and saturated market in Asia.
However, it has made an improvement from its score a year ago, highlighting progress that downstream
expansion plans have made in the first half of 2013. In terms of risks, low scores for corruption, rule of law
and physical infrastructure have dragged down its score, especially when compared to more sophisticated
downstream markets in the region such as South Korea, Japan and Singapore.
Page 44
Market Overview
Vietnam Energy Market Overview
The bulk of Vietnam's oil and gas reserves are
located offshore in the Cuu Long and Nam Con Son
Source: BMI
If the wrangling over offshore blocks continues, then there is a serious chance that exploration could be
disrupted or delayed. This would be very bad news for Hanoi, as the government is banking on new
deepwater projects to boost long-term reserves and production. Beijing also issued a warning against further
encroachment into disputed waters in December 2012.
However, firms might be increasingly willing to take the risk. UK independent Soco International could
sign for acreage in the disputed waters. In an interview with Bloomberg in September 2012, chief executive
Ed Story said he believed in the 'very significant potential' of deepwater acreage in the claimed areas and is
'willing to take measures of risk'. Other less risk-averse small independents, with no interest in China, could
follow.
Page 45
In November 2013, PetroVietnam offered India's ONGC Videsh a block for exploration in the South China
Sea, as part of a memorandum of understanding (MoU) committing to deeper cooperation between the two
companies. Similarly, during negotiations over a raft of bilateral agreements between Rosneft, Gazprom
and PetroVietnam in the same month, Russia also reportedly expressed interest in exploring in the dispute
territory. However, given the potential political fallout, we believe that the probability of either country
entering the South China Sea remains relatively low. Oil and liquids production rebounded from a dip to
reach 363,500 barrels per day (b/d) in 2012, according to the EIA. In the short-term, new projects will keep
output on an upward trend, offsetting declines at maturing fields such as the flagship Bach Ho.
Nevertheless, over the long term, a lack of major new projects will see Vietnamese production enter decline.
That will see Vietnam's net crude import requirement rise to 101,630b/d by 2023.
By contrast, gas production will rise steadily as new developments gradually come on-stream. However,
demand for gas will quickly exceed supply with LNG imports forecast to begin in 2015, rising steadily to
approximately 5.8bn cubic metres (bcm) by 2023.
Overview/State Role
The government of the Socialist Republic of Vietnam controls both the upstream and downstream segments,
although gradual liberalisation is under way. PetroVietnam is the national oil company, and consistently
ranks as one of the country's top five taxpayers. In the upstream segment, foreign companies are allowed to
independently explore for oil and gas. While the presence of PetroVietnam is required in all producing
projects, international oil companies (IOCs) are allowed to hold majority stakes and receive a share of
output.
The government has issued over 80 investment licences for oil and gas exploration since the industry was
opened to foreign partners in 1998. More than 30 companies from around the world now operate offshore
Vietnam. However, several foreign firms have chosen to exit the country citing regulatory problems and
disappointment at recovering smaller quantities of oil and gas than expected.
The downstream segment remains under full state control (with the exception of LPG), although proposals
for reform have been on the table for some time. PetroVietnam's downstream subsidiary PV Oil operates
the country's only refinery, while fuels retailing is carried out by government-run companies, such as
Petrolimex and Petec under the Ministry of Trade, PetroVietnam Trading Company (Petechim) under
PetroVietnam, Saigon Petro under Ho Chi Minh City People's Committee, Military Petroleum Company
under the Ministry of Defence and Vinapco under Vietnam Airlines, all of which have been licensed to
Page 46
import petroleum products. Petrolimex is the country's largest fuel importer and distributor. Fuel prices are
heavily subsidised for political purposes.
Despite a more liberal LPG market, Vietnam has seen high profile IOCs pull out of its LPG market ExxonMobil in 2006, BP in 2009 and Shell in 2012. Profitability has been hit by the proliferation of LPG
suppliers selling counterfeit LPG products masqueraded as the more reputable brands.
PetroVietnam's subsidiary Binh Son Refining and Petrochemical Company is looking to divest a 49%
stake in its Dung Quat crude refinery in Quang Ngai province, according to Binh Son's CEO Nguyen Hoai
Giang. PetroVietnam was in discussions with Nippon Oil & Energy Corporation, Petrleos de
Venezuela (PdVSA) and a South Korean firm with regard to the divestment, Giang added. However, the
government put an end to expansion plans in April 2013, though PetroVietnam is still looking to embark on
upgrades for Dung Quat.
Permits are awarded on a bilateral basis, with no regular upstream bidding rounds. Amendments to
Vietnam's Petroleum Law in 2000 paved the way for a more open and transparent licensing round scheme,
through which exploration and production (E&P) projects would be offered to international investors.
The 2011 Licensing Round, announced by PetroVietnam, covered nine blocks in the Nam Con Son, Phu
Quoc and Malay-Tho Chu basins, offshore Vietnam. The round opened on August 1 2011 and closed on
January 5 2012. The database included approximately 49,000km of seismic 2D, 1,700sq km of acquired
seismic 3D and 33 wells that had already been drilled - showing similarity to recent oil and gas discoveries
in the country and the region. According to PetroVietnam, the recently improved legal framework and
investment conditions make the contract and fiscal terms more attractive.
Taxation
Overall, the government understands the importance of IOC investment in maintaining oil and gas output.
The state is therefore generally committed to establishing an attractive tax framework for foreign energy
investors. However, the negative impact of the economic downturn on the country's fiscal position has led
to rises in some oil taxes. In April 2008, the finance ministry raised the crude export tax from 4% to 8%. In
Page 47
January 2009, crude production royalties went up by 2%, increasing the overall level to 10% for
20,000-50,000b/d fields and 6-8% for smaller ones.
Moreover, in July 2009 the government announced it was discussing a proposal to impose a windfall tax on
oil production to maximise state revenue in times of high oil prices. Under the proposal, foreign producers
would have to pay 50% of their annual profit in years when oil prices rise by more than 20%. The windfall
revenues would then be transferred to the Fuel Fund, which is used to subsidise domestic fuel prices.
Some recent measures, on the other hand, have benefited domestic fuel importers. In an attempt to stimulate
consumer demand, in 2009, the government significantly reduced the import tariff on oil products. By late
April 2009, petrol and diesel duty had fallen to 20%, down from 40% in January. The decision to slash
import taxes was justified by the start-up of domestic refining that was expected to reduce the level of oil
product imports.
A more fundamental shift in import duties followed in January 2011, when the government brought in an
automatic tariff tracker. Although they were previously set centrally by the Finance Ministry, as of January
2010 the tariffs have been based on Platts' 30-day average price of Singapore-traded WTI crude. The
biggest importer, Petrolimex, now publishes pricing information on its website.
Consequently, import tariffs fell following the introduction of the tracker in light of the rising oil prices. In
January 2011, Petrolimex cut the import tax rates on gasoline and jet fuel by half to 6% from 12%, the
company said in a statement. The import tax on diesel was reduced to 2% from 5%, while the import tax on
kerosene was cut to 4% from 10%. The gradual relaxation of oil product import tariffs was made possible
by the start-up of domestic crude refining in Vietnam in early 2009, which reduced the fiscal importance of
import duties to the government. Moreover, the build-up of refining capacity throughout the decade should
practically eliminate the country's need to import the main types of distillates.
In November 2012, a draft PSC prepared by the Ministry of Industry and Trade suggested that taxes on
crude oil production of up to 20,000b/d be raised from 4% to 7% for preferred projects, while non-priority
projects could see a hike of 6% to 10%. Deepwater projects will likely be given tax preferences. Gas
projects, which are currently tax-exempt, could also see the introduction of a 1-2% tax for governmentpreferred and non-preferred projects respectively.
Page 48
Prices
Fuel prices are regulated by the Ministry of Finance and the Ministry of Industry and Trade. Prices are
supported by the fuel price stabilisation fund, which sellers can dip into to make up for extreme losses they
might otherwise incur when crude prices are high; as of December 2013, domestic retail prices for fuel were
on average VND914-1,414 US$0.03-0.05 per litre cheaper than international market prices.
The government has relaxed its control on prices. At present, fuel suppliers can adjust prices from the
official figure by 7%, but have to apply to the finance ministry for permission. Platts reports that the
ministry usually takes 4-5 days before announcing its decision, according to Dao Minh Hai, Deputy
Director of the Department of Market Management in the Ministry of Industry and Trade.
The time lag has been abused as fuel suppliers hoard their supplies so that they can sell them at a higher
price when price adjustments are approved. In October 2012, Deputy Prime Ministry Hoang Trung Hai
called for the finance ministry to be quicker in assessing proposals for price changes so as to reduce these
hoarding tendencies.
However, these subsidies - via the fuel price stabilisation fund - are taking a toll on the country's fiscal
position. BMI's Country Risk team holds the view that Vietnam's costly welfare subsidies will need to be
gradually withdrawn as part of the government's broader efforts to fix its fiscal imbalances and as such, we
expect further price hikes to come even if global crude prices were to stabilise at current levels.
Other Regulations
The Ministry of Sciences and Technology regulates the LPG and petroleum business, but has been unable to
impose uniform standards throughout the industry. This has resulted in the emergence of low quality fuels
undercutting legitimate supplies and the profitability of fuel retailers.
In October 2012, Vietnam News reported that 13% of over 5,200 businesses inspected by the ministry were
found to have violated sector regulations. Chief inspector Tran Minh Dung said that the offence rate has
dropped - from 29% in 2003 and 18% in 2008 - but monitoring is increasingly difficult.
The number of regulations could increase in the country's bid to ensure better petroleum quality in the
market. According to inspector Dung, 'it is necessary to have more regulations to ensure better quality
control'.
Page 49
Government Policy
Under government proposals announced in July 2009, deputy trade minister Nguyen Cam Tu said private
Vietnamese companies would be allowed to import and sell refined products as long as they had adequate
storage facilities and terminals. In addition, the draft measure permitted oil product distributors to change
pump prices by up to 7% if world crude prices jumped by more than 12%, although the state would still
intervene in the event of abnormal changes in world prices.
The government announced Petrolimex, the largest national fuel distributor, could be put up for sale as part
of its renewed privatisation drive. Prime Minister Nguyen Tan Dung announced in January 2009 that the
state was to reduce its holding in Petrolimex to at least 75% to help balance the country's budget.
Partial privatisation of Petrolimex, which controls around 60% of the Vietnamese fuels market through its
6,000-strong network of petrol stations, is part of the wider liberalisation of the country's downstream
segment. In the summer of 2009, the government began debating proposals to allow importers of refined
products to trade futures contracts and to permit private domestic operators in the fuels market. Price caps at
the pump were also relaxed in H209, although December 2009 saw the government threaten to bring fuel
pricing back under full state control.
Since 2005, PetroVietnam has floated and sold stakes in several subsidiaries, including PetroVietnam
Drilling & Well Services and Petroleum Technical Services. The firm appears to be slowly privatising
itself, with the government having been mulling an international public stock offering for some time. The
global economic crisis has put plans for a large-scale privatisation on ice, but those plans began to move
forward again as of early 2011.
As a socialist country, Vietnam has maintained close ties with Russia. Surprisingly, those ties remained
strong after the collapse of the Soviet Union and Russia arguably remains the most important foreign player
in Vietnam's oil and gas industry despite the opening up of the sector to Western firms.
Vietnam and Russia signed an agreement in late-December 2010 extending oil E&P cooperation in the
Asian country's waters past 2010. The life of a joint venture (JV) between PetroVietnam and Russia's
Page 50
Zarubezhneft - Vietsovpetro - is to be extended under the agreement, up to 2030. The venture was due to
expire by the end of 2010, under an agreement signed in 1991.
In October 2011, Russia's Lukoil said it received Vietnamese government approval for its purchase of a
50% stake in a Vietnamese offshore block estimated to hold 180mn tonnes of oil equivalent. Vietnam
continues to strengthen cooperation with Russian state-owned companies in the upstream: in April 2013, it
signed an agreement with Gazprom to look into further areas of cooperation, particularly in LNG marketing
and in the production of fuels for natural gas vehicles (NGV).
In November 2013, Vietnam and Russia signed 17 bilateral agreements, five relating to the oil, gas and
energy sectors; the agreements covered oil trade, exploration activities and liquefied natural gas. An
agreement was also signed by PetroVietnam fixing the terms of Gazprom Neft's proposed acquisition of a
stake in the Dung Quat refinery, alongside plans for the refinery's modernisation.
India
In November 2013, India's state-run explorer Oil and Natural Gas Corporation (ONGC) signed an MoU
with PetroVietnam to promote joint cooperation in the hydrocarbon sector in Vietnam, India and other
countries. The MoU is in furtherance to a three year agreement signed in October 2011, under similar terms.
ONGC Videsh has been operating in Vietnam since 1988; it currently holds a 100% operated stake in
exploration Blocks 127 and 128 in the Phu Kanh basin, which it was awarded in 2006. Under the 2013
MoU, PetroVietnam has offered ONGC Videsh a further five blocks, which are now under assessment.
Sri Lanka
The governments of Sri Lanka and Vietnam signed two contracts on October 14 2011, according to Sri
Lanka's External Affairs Secretary Karunatilaka Amunugama. He said that under the terms of the first
contract, Sri Lankan national oil and gas company Ceylon Petroleum will buy oil from state-run
PetroVietnam. The second contract involves a technological partnership to explore oil and gas reserves,
Amunugama added.
Page 51
Its refining capacity could rise further if the expansion of Dung Quat goes ahead and an investment
commitment is made for other refineries - PetroVietnam's Long Son, Petrolimex's Nam Van Phong and
PTT's mega Nhon Hoi complex.
Refinery
Dung Quat
Capacity
(b/d)
Status
Owner (Contractor)
Completion
Cost
(US$bn)
140,000
Active
PetroVietnam
2009
2.5
2017
Nghi Son
200,000
Planned
100,000 Proposed
PetroVietnam
na
1-2
200,800 Proposed
na
4.8
Long Son
200,900 Proposed
na
Nhon Hoi
660,000 Proposed
na
2019
na
Vung Ro
160,720 Proposed
na
na
*To be confirmed; na = not available. Source: Vietnamplus, Reuters, Company Data, BMI
Dung Quat
Dung Quat is owned by operating joint venture Binh Son Refining and Petrochemical Co, of which
PetroVietnam is a partner in, and came online in 2009. It provides for about a third of Vietnam's fuel
requirements. However, it has been plagued with persistent outages that have hit output.
In April 2013, the government ordered PetroVietnam to cancel plans to increase the refinery's capacity,
although allowing them to proceed with planning a modernisation programme planning that would enable
Page 52
the plant to process a greater diversity of feedstock than the sweet Bach Ho crude it currently uses. It had
previously mentioned that it is considering the use of Middle Eastern and Venezuelan crudes. Investment
for this upgrade is subject to approval from the government and the national oil company (NOC) was
invited to submit its plans by September 2013.
In November 2013, it was announced that Gazprom Neft and PetroVietnam had signed a framework
agreement for joint investment in the Dung Quat refinery, with the Russian giant looking to acquire a 49%
stake in the Binh Son Refining and Petrochemical Co. Gazprom Neft claimed that the investment would
cover an almost doubling of the refinery's capacity, as part of a broader modernisation drive. However, this
has yet to be independently confirmed by either PetroVietnam or the Vietnamese government.
Ba Ria-Vung Tau
PetroVietnam also owns a small refinery that processes condensate into gasoline. This condensate plant has
a capacity of 2,610b/d and produces about double the input amount of gasoline. The state-owned firm is
planning to double its capacity by 2018.
After years of deliberation and delays caused by financing problems, it has finally been confirmed that the
Nghi Son refinery in the northern province of Thanh Hoa will proceed with construction. On January 15
2013, Idemitsu announced that it has approved a US$9bn investment - higher than the original estimate of
US$7.5bn - required to build the 200,000b/d refinery, which will be Vietnam's second after Dung
Quat. Crude feedstock will be sourced from Kuwait. Construction started in October 2013, which could see
it coming online after 2017.
Development will comprise both onshore and offshore installations - the main refinery and petrochemical
complex on land and accompanied by a marine harbour that will require main breakwater, access channel,
turning basin, intake channels, a crude oil pipeline and a single point mooring to be installed.
Idemitsu Kosan holds a 35.1% stake in the project and Kuwait Petroleum, via its marketing arm Kuwait
Petroleum International, holds the other 35.1%. The remaining interest is held by stateowned PetroVietnam (25.1%) and Mitsui Chemicals (4.7%). A consortium formed by
Chiyoda Corporation, JGC Corporation, Technip, GS Engineering and SK Engineering has been
awarded the engineering, procurement and construction (EPC) contract to build the plant. Foster Wheeler
will manage the project and provide consultancy services.
Page 53
Vung Ro is in line to be Vietnam's third refinery after the government approved plans to double its refining
capacity to 160,720b/d in February 2013. It will be located in the Hoa Tam Industrial Zone in Dong Hao
District, Phu Yen province. Crude oil for the project will be sourced from the Middle East and from Russia.
The UK's Technostar Management and Russian firm Telloil Group are partners in this project.
It was first proposed in 2007 as a US$1.7bn project to produce liquefied petroleum gas (LPG), gasoline,
diesel, benzene, polypropylene and other petrochemical products. Its investors made a decision to increase
capital investment to US$3.18bn in July 2013. It awarded JGC with a front-end engineering design (FEED)
and signed a letter of intent for engineering, procurement and construction (EPC) to JGC. Construction
began in October 2013, and the project is slated for completion by 2018.
The Long Son project in the southern province of Ba Ria-Vung Tau is a proposed 200,900b/d plant. The
project is still in the planning stage, and little progress has been made on securing other investors.
PetroVietnam estimates that the refinery will only come online after 2020, at a cost of about US$8bn.
In July 2008, Petrolimex announced plans to build an oil refinery in the country's central Khan Hoa
province. The US$4.5bn facility, known as Nam Van Phong, will have the capacity to process 10mn tpa,
equal to some 200,900b/d, and will produce LPG, gasoline, kerosene, diesel, polypropylene, benzene and
some other products. Crude oil for the facility will be imported from either Singapore or the Middle East.
Petrolimex has been negotiating with several partners for the project including China's Sinopec and Saudi
Aramco, according to local media. However, there appears to have been little progress towards a final
development plan. Given the perennial delays to Vietnam's Dung Quat refinery, we do not expect plans for
the Nam Van Phong refinery to progress in the short term.
Thailand's state-owned PTT is contemplating a US$28.7bn refinery and petrochemical project in the Binh
Dinh province of Vietnam, according to Vietnamese paper Tuoi Tre. This would be near the port of Nhon
Page 54
Hoi. The proposed capacity of the plant is 660,000b/d, which would make it by far the largest refinery in
Vietnam.
PTT chief executive Pailin Chuhottaworn stated that the refinery would serve the domestic market. Crude
oil would be imported from the Middle East (45%), Africa (25%), South and Central America (35%) as
feedstock for the plant's operations. Pending approval from the Vietnamese government, the Thai company
will decide 'if we want to invest'. A feasibility study began in August 2013 and is to be completed by April
2014. If the proposal moves ahead, construction could commence in 2016 and the plant could be operational
by 2019.
At 660,000b/d, the capacity of PTT's proposed Ngon Hoi plant alone would exceed Vietnam's projected
domestic consumption of 542,400b/d if it is operational by 2020 as scheduled. PTT likely has plans to
export some of this production to the region, supported by its location by a deepwater port. As the plant
would most likely be an integrated refining and petrochemicals complex, its large size would allow it to
reap the economies of scale from production. However, the project economics of the plant, even as an
export-oriented project, could be challenging - crude feedstock imports could be costly and exports will face
intense competition from other major refineries in the region and globally.
A memorandum of understanding (MoU) to set up the refinery was signed between the People's Committee
of Binh Dinh Province and PTT in March 2013. However, PetroVietnam has filed a complaint against the
project to the Ministry of Industry and Trade, on grounds that the location of Nhon Hoi is too close to Dung
Quat, the planned Vung Ro project and the proposed Van Phong plant to justify another refinery. Most
importantly is PetroVietnam's fear that this mega-refinery will lead to a production surplus in the country by
2025, which will in turn limit PetroVietnam's selling power.
An underground oil storage facility in Dung Quat is being planned. The facility will have a capacity of
3.8mn bbl of oil at a cost of about US$150mn. In May 2013, Korea National Oil Company (KNOC)
joined the project, which had been led by PetroVietnam, taking a 71% in it. KNOC is planning to invite
Page 55
other players - ranging from engineering firms and financial investors - to join the facility's development.
KNOC also commented that the facility could be ready in three and a half years - or by 2017.
A larger 3mn tpa (4.14bcm) LNG terminal at Binh Thuan, Son My, has also been proposed for a 2020 startup, though details of this are unavailable at the time of writing.
Gas Pipelines
Nam Con Son
Vietnam's largest pipeline, Nam Con Son, is operated by TNK-BP. It transports about 4.8bcm per annum of
gas from the offshore Lan Tay-Lan Do gas field onshore to the Phu My gas distribution centre in Ba Ria
Vung Tau province. Its maximum capacity is 20mn cubic metres per day.
PetroVietnam has said that it plans to spend US$1.3bn building a second gas pipeline from the Nam Con
Son Basin to southern Vietnam, according to state media reports. The planned US$1.3bn pipeline would
transport gas 400km from the Hai Thach, Moc Tinh, Thien Ung and Mang Cau gas fields to a new onshore
processing facility and the on to power plants in the Phu My district of the Ba Ria-Vung Tau province.
The Vietnamese government awarded the engineering, procurement and construction (EPC) contracts for
the project in July 2011. PetroVietnam Construction and PetroVietnam Equipment Assembly and
Metal Structure Company were awarded contracts worth an estimated US$441mn for the construction of
a 7.3bcm gas-processing plant and onshore pipeline system for the project. The pipeline is due to be
completed in 2014 and will increase Vietnam's gas supply by 30-40% to 10-11bcm per annum, according to
PetroVietnam's general director, Phung Dinh Thuc.
Page 56
Gas discoveries in south-western Vietnam have encouraged the construction of pipelines to feed the rapid
expansion of the country's power generation capacity, particularly at the Phu My complex. Vietnam is also
boosting the use of associated gas production.
In March 2010, US oil major Chevron signed a deal with state-run energy group PetroVietnam to build a
pipeline from its operated offshore assets in the Cuu Long Basin to southern Vietnam. The deal was a
significant step forward for the so-called Vietnam Gas Project, which aims to commercialise reserves at
Block B, 48/95 and 52/97.
Under the deal, Chevron, PetroVietnam and minority partner PTTEP of Thailand agreed to spend US$1bn
to build the 400km pipeline, the longest in the country. The proposed pipeline would run from production
platforms about 250km off the coast to power plants in Can Tho City, with offshoots supplying power and
fertiliser plants throughout the south-western region. The pipeline was to have carrying capacity of 6.4bcm
a year. The midstream section of the Vietnam Gas Project was to be operated by PetroVietnam subsidiary
PV Gas (51%) in partnership with Chevron, PTTEP and Japan's Mitsui, which was selected as the main
contractor. The upstream phase was to be operated by Chevron. The total cost of the Vietnam Gas Project
was estimated at US$4.3bn, and Chevron expected to begin production in 2014, two years behind the
original schedule, with output potentially reaching 5.1bcm per annum. While the initial volumes had been
earmarked for local industrial customers, Chevron proposed to construct an interconnector to Malaysia and
Thailand, an option highlighted in PetroVietnam's press release on the Can Tho pipeline deal.
However, in November 2013, Chevron announced its decision to relinquish its operating stake in the Block
B gas development. The oil major said the decision was made after failing to agree commercial terms on gas
prices with PetroVietnam. Although Vietnam has relaxed its pricing environment in recent years, with
prices increasing from around US$3 per British Thermal Unit (/BTU) to around US$6-8/BTU, it is
understood that Chevron was looking for a price pushing US$10/BTU.
It will likely take around six months for Chevron to transfer operatorship of the project, with Gazprom and
Talisman Energy flagged as possible replacements.
It transports gas from the offshore Cuu Long field to be processed at the Dinh Co Gas Processing Plant. Dry
gas is then transported through the pipeline system to Ba Ria and Phu My for commercial use.
Page 57
The first leg of the network - Bach Ho-Long Hai-Dinh Co - came online in 1995 and transports gas from the
Bach Ho field to the Dinh Co Gas Processing Plant. It is 116.5km-long and has a send-off capacity of
6mcm/d - or 2.19bcm per year.
It was later joined by the 46.5km-long Rang Dong-Bach Ho extension in December 2001, and the 43.5kmlong connected from Su Tu Vang field to Rang Dong in 2009. At full capacity, the pipeline will be able to
transport 1.1bcm per year.
This pipeline delivers dry gas processed at the Dinh Co Gas Processing Plant to Phu My, where it is
distributed to end users. The total length of the pipeline is about 28.8km.
This pipeline transports gas from the Nam Con Son field to Nhon Trach and Hiep Phuoc and is fed into
power plants and industrial zones along the route. It was inaugurated in 2008.
The 330km-long pipeline delivers gas from the offshore PM3 CAA & 46-Cai Nuoc fields to the Ca Mau
Gas Distribution Centre. It feeds into two power plants and a fertiliser plant in the Ca Mau industrial area,
which was launched in October 2012.
In August 2009, PetroVietnam also said it was planning to build a 398km gas pipeline to transport gas from
a field offshore the south-west coast to power plants in the city of Can Tho at a cost of US$1bn. The
company said the pipeline would have a capacity of 5.8-6.6bcm and would be constructed by RussoVietnamese JV Vietsovpetro, although it was not specified which field would supply the gas.
Page 58
Competitive Landscape
Competitive Landscape Summary
The main government vehicle is PetroVietnam, which, with its Vietsovpetro joint venture (JV),
provides the bulk of the country's oil production. Vietsovpetro has announced plans to increase its oil
output to 140,000boe/d in 2015, but has reported a further decline in output during 2013. Vietsovpetro
currently accounts for around 40% of Vietnamese crude oil production and operates the country's largest
field, the highly mature Bach Ho (White Tiger).
A gas discovery offshore Vietnam helps to support the country's buoyant upstream segment. A Japanese
consortium of Idemitsu, JX Nippon and Inpex confirmed a gas discovery made in Blocks 05-1b and
05-1c in the Nam Con Son Basin. It is the third well to be drilled in the blocks, and the find was backed
by tests that determined 'accumulations of gas and condensate', according to the official statement. The
venture partners will further appraise the well to evaluate its reserves potential and to identify other
targets in the blocks.
French independent Perenco owns three subsidiaries in Vietnam. The subsidiaries hold a 23.25%
participating interest in Block 15-1, a 36% participating interest in Block 15-2 and a 16.3% participating
interest in the Nam Con Son Pipeline. Those stakes were previously owned by US-based
ConocoPhillips. Gross production is 75,000 barrels per day (b/d).
Thailand's state-owned PTT is contemplating a US$28.7bn refinery and petrochemical project in the
Binh Dinh province of Vietnam, according to Vietnamese paper Tuoi Tre. This would be near the port of
Nhon Hoi. The proposed capacity of the plant is 660,000b/d, which would make it by far the largest
refinery in Vietnam.
TNK-BP acquired the assets of UK-based oil major BP in Vietnam. The key investment is the US$1.3bn
Nam Con Son Gas project. TNK-BP has a 35% field interest, operates the gas pipeline and owns a third
of the Phu My 3 power plant. Rosneft of Russia is now the owner of TNK-BP, renamed TNK Vietnam.
Petronas has shares in eight blocks, including offshore Blocks 1 and 2 that contain the Ruby, Emerald
and Topaz fields. The company's other producing asset is Cai Nuoc in Block 46. Petronas operates
liquefied petroleum gas (LPG) import, storage and distribution JVs.
Chevron hopes to start gas sales from its Vietnamese fields by 2014. It has discovered 70bcm of gas
reserves in the Kim Long, Ac Quy and Ca Voi fields. The US firm is planning to invest a further US
$1.5bn over the next five to seven years in various gas and power projects. Chevron is the operator in two
PSCs in Vietnam. They are in the northern part of the Malay Basin, off the coast of south-west Vietnam.
Chevron has a 42.4% interest in a PSC that includes Blocks B and 48/95. It also has a 43.4% stake in a
PSC that covers Block 52/97.
ONGC Videsh (OVL), the international subsidiary of Indian state-run oil and gas company ONGC, is
considering acquiring a stake in Chevron's Block B gas project in Vietnam. Chevron, which owns a
42.38% stake in the US$4.3bn Block B, is seeking expression of interests from global companies ready to
farm-in or purchase a stake, according to unnamed sources. Vietnam's block B is estimated to have
0.113trn cubic metres of total in-place reserves, of which 63% are recoverable reserves.
Premier Oil has announced that it has sold 100% of shares in its subsidiary Premier Oil Vietnam South
(POVS) to an undisclosed buyer for an initial US$100mn. The deal gives the buyer control of POVS's
30% operated interest in Block 07/03, offshore Vietnam, which houses the Ca Rong Do oil and gas
discovery and the Ca Duc (Silver Sillago) exploration prospect.
Page 59
The most active independents are UK-based Soco and Canada's Talisman Energy. Talisman has brought
online its Hai Su Trang and Hai Su Den development offshore Vietnam. The company expects to achieve
gross production of 15,000b/d from the deepwater field.
Petrolimex has announced it plans to invest up to US$4.8bn in the construction of the 200,000b/d Nam
Van Phong refinery. The company is also looking into a US$212mn project to build an oil products
import pipeline from China to help meet the country's rapidly growing fuels demand.
Italy's Eni has identified new prospects in the Phu Khanh basin offshore Vietnam. The company had
conducted a 3D seismic shoot over block 120, which spans across 8,469 square kilometres in the Phu
Khanh basin. Block 120 is identified as having 12 oil leads with prospective resources of 633mn-7.9bn
barrels.
A US$9bn refinery project is being undertaken by Nghi Son Refinery and Petrochemical, a JV owned
35.1% each by Japan's Idemitsu Kosan and Kuwait Petroleum International, 25.1% by PetroVietnam
and 4.7% by Mitsui Chemicals. Local sources said it is considered 'the largest foreign investment project
in Vietnam'. The complex includes a refinery to process 200,000b/d of Kuwaiti crude and facilities
designed to produce 700,000 tpa of paraxylene, 370,000 tpa of polypropylene and 240,000 tpa of
benzene. Commercial operations are expected to begin in mid-2017.
Russian energy giant Gazprom, in association with PetroVietnam, is planning to develop the 05.2 and
05.3 blocks in the South China Sea. The project, in which Gazprom will take a 49% interest, is to be
carried out under a production sharing agreement (PSA). The blocks hold two discovered gas and
condensate fields, dubbed Moc Tinh and Hai Thach, with total reserves of 55.6bcm of gas and 25.1mn
tonnes of condensate.
Japan's Tokyo Gas and PetroVietnam Gas have signed a memorandum of understanding (MoU) to
jointly develop Vietnam's liquefied natural gas (LNG) value chain. Tokyo Gas Engineering will carry out
front-end engineering and design (FEED) for Vietnam's first LNG receiving terminal, with the plant
expected to become operational in 2015. The companies will also work towards procuring LNG, will
develop downstream natural gas demand and LNG infrastructure, and are considering generating
electricity using LNG.
Company
No. of
employees
Year
established
Total assets
(US$mn)
Ownership (%)
PetroVietnam
265
100
17,000
1975
na
100% state
Vietsovpetro
3.19
100
na
1981
na
50:50 PetroVietnam/
Zarubezhneft
TNK Vietnam
na
na
700
1989
na
100% Rosneft
Page 60
Company
Oil/liquids production
(000b/d)
PetroVietnam
327
85e
8.01
71e
(128)2
(40e)3
(1.30e)
(11e)
KNOC
16.4e
4.2e
0.50e
4e
na
na
0.65
6e
0.74
na
1.854
16e
12.53
na
0.043
na
TNK Vietnam
ONGC Videsh (OVL)
Petronas
Company
Retail outlets
Petrolimex
na
na
1,871
51
140
100
256
na
BP Petco
na
na
na
na
Petec
na
na
na
13e
Saigon Petro
na
na
1,000e
10e
Vinapco
na
na
Na
2e
PV Oil/Petechim
Page 61
Company Profile
PetroVietnam
SWOT Analysis
Strengths
Weaknesses
Opportunities
Threats
Company Overview
Vietnam National Oil and Gas Group (PetroVietnam) is responsible for oil and gas
exploration and production (E&P), storage, processing, transportation, distribution and
related services. The company accounts directly for 20% of Vietnam's oil production
and half of its gas production. Its PetroVietnam Exploration Production (PVEP) unit
manages all upstream operations, while PV Oil is the main downstream subsidiary and
PV Gas is responsible for gas distribution. The company operates alone or in
partnership with international oil companies (IOCs) under joint operating company (JOC)
contracts, similar to a production sharing contract (PSC), in which a Vietnamese legal
entity acts as an agent on behalf of the contracting parties, with each party contributing
Page 62
staff to the operating company. However, there are plans to offer IOCs sole control of
the fields.
Strategy
PetroVietnam is planning to produce 4.6mn tonnes of oil products in 2014, 30% less
than in 2013, due to planned maintenance work at its Dung Quat refinery during MayJuly. The maintenance is scheduled to take place for about 52 days, from May 19 to
July 9 2014; however, the company said it will try to shorten this period. The Dung Quat
refinery produced around 6.6mn tonnes of oil products in 2013, 18% higher than the
2012 level.
Vietnam is considering expanding its deepwater plays to meet the country's increasing
energy demands amid declining energy production. PetroVietnam plans to expand its
deepwater activity; however, it is facing technical, human resource and financial
problems in targeting the deeper offshore plays, said company Vice President Nguyen
Quoc Thap. Quoc Thap urged the fellow Association of Southeast Asian Nations
(Asean) member states to cooperate with Vietnam and help it to fulfil the region's rising
energy needs.
Vietnam's Deputy Prime Minister Hoang Trung Hai has said PetroVietnam should
expand its oil and gas activities overseas in a bid to conserve domestic resources,
reports Vietnam Plus. The move would enable the company to guarantee energy
security despite difficulties and challenges, Hai added. He urged the company to build a
long-term strategy for the oil and gas sector, which is expected to play a significant role
in energy security in the coming decades.
Vietnam intends to strengthen cooperation with the State Oil Company of Azerbaijan
Republic (Socar), reports APA-Economics, citing Vietnam's Deputy Foreign Minister
Nguyen Phuong Nga. The minister also underlined the significance of documents
signed between Socar and PetroVietnam during her first state visit to Azerbaijan.
PetroVietnam and Russia's oil and gas giants have discussed and initially agreed on
several deals for upstream partnerships in each country, PetroVietnam said in an April
2013 statement. During a meeting between PetroVietnam Chairman Phung Dinh Thuc
and Zarubezhneft's General Director Sergei Kudryashov, the two companies agreed to
establish a Russia-based joint venture to operate in three offshore blocks in the Caspian
and Pechora seas as well as new blocks on Vietnam's continental shelf, PetroVietnam
said.
PetroVietnam and Russia's state-controlled Rosneft plan to sign a new petroleum
contract and an agreement for cooperating in oil projects in onshore and offshore areas
of Russia, PetroVietnam said. Rosneft has been in negotiations with PetroVietnam over
cooperation for some time, and since completing acquisition of TNK-BP earlier in 2013,
has controlled TNK-BP's Vietnamese subsidiary TNK Vietnam.
PetroVietnam did not elaborate on the petroleum contract, but a source familiar with the
matter said earlier that TNK Vietnam has bid for one of the nine offshore blocks that
PetroVietnam offered in a 2011 bidding round. PetroVietnam and TNK Vietnam are
Page 63
waiting for the signing of the contract, the source said. PetroVietnam and Rosneft have
agreed that Rosneft would expand its oil and gas operations in Vietnam and supply the
country with crude oil through long-term contracts, the PetroVietnam's statement
added.
In a meeting between PetroVietnam chairman Thuc and his Gazprom counterpart,
Alexey Miller, the two sides paid special attention to their potential cooperation in the
area of natural gas use as a motor fuel, Gazprom said in a statement. They discussed
progress on joint projects offshore Vietnam, the statement said, noting that exploration
activities in blocks 112 and 129-132 were successful.
Gazprom and PetroVietnam also identified ways to cooperate in LNG marketing,
including the possible conclusion of a long-term LNG supply contract, Gazprom said.
They signed a memorandum of understanding in July to supply Vietnam with Russian
LNG. Separately, PetroVietnam and Gazprom's subsidiary, Gazprom Neft, plan to sign a
deal to cooperate in the upstream sectors of Vietnam and Russia, invest in the
petrochemical and refining sectors, and sell petroleum products in Vietnam,
PetroVietnam said. PetroVietnam has a 49% stake in Russia-based GazPromViet, and
Gazprom holds the remaining stake. Gazprom, meanwhile, holds a 49% share in
VietGazprom JV in Vietnam, with PetroVietnam controlling the remainder.
The group appears to be slowly moving towards privatisation, spinning off non-core
subsidiaries such as its insurance, real estate and tourism business, as well as some
oil-related service companies. Auctions of various subsidiaries suggest the company
aims to privatise its assets selectively, keeping the strongest profit generators under
state control.
PetroVietnam may seek Japanese partners to develop as many as 20 offshore blocks in
the South China Sea, according to business daily, Nikkei. PetroVietnam is thought to be
seeking as much as US$24.8bn in new upstream and downstream investment.
PetroVietnam, recently announced it will continue to buy foreign oil and gas assets to
produce nearly 100,000 barrels per day (b/d) overseas by 2020, The Wall Street Journal
reported. The company said by increasing foreign oil, production could be brought
home for refining to help meet the country's rising energy demand. Vietnam is looking
to explore in an area about 200 nautical miles from the country's coast. However, the
country is in a territorial dispute with China, and the WSJ said that could shadow
offshore prospects. 'So far we have not made commercial discoveries [in disputed
areas], but if there are commercial discoveries - and I am optimistic that we will have
them - then we will start developing them if they are within our continental shelf,' said
Do Van Hau, president and CEO of PetroVietnam.
In the downstream segment, PetroVietnam is involved with a number of refinery
construction projects as it strives to reduce the country's dependence on fuel imports.
Petrovietnam has been told by the government to scrap plans to expand capacity at its
Dung Quat refinery. However, the 130,000b/d plant will be upgraded. 'Upgrading the
refinery so that it can process a diversified feedstock will cost less than expanding its
Page 64
capacity,' Petrovietnam unit Binh Son Refinery chairman Nguyen Hoai Giang said in the
statement. Petrovietnam will submit upgrade plans to the Prime Minister by September
2013. Petrovietnam had earlier said it planned to sell a 49% stake in the refinery to
foreign investors and use the proceeds to expand capacity to 200,000b/d.
Petrovietnam, and its partners from Japan and Kuwait, broke ground for the
construction of Vietnam's second oil refinery in October 2013. The US$9bn Nghi Son
complex, to be located 180km south of Hanoi, will have a refining capacity of 200,000b/
d and should be fully operational in 2017. It will process Kuwaiti crude oil supplied
exclusively by Kuwait Petroleum International.
PetroVietnam and China National Offshore Oil Corporation (CNOOC) have extended an
agreement to jointly explore oil and gas in the Gulf of Tonkin offshore Vietnam to
end-2016. Under the terms of the extended agreement, the two sides have expanded
the area for joint exploration to 4,076sq km from 1,541sq km, covering two equal parts
on each side. The accord will be carried out by both sides with expenses divided
equally. The extension was agreed during Vietnamese President Truong Tan Sang's
official visit to China in the week ended June 22 2013.
Market Position
PetroVietnam is responsible for oil and gas E&P, storage, processing, transportation,
distribution and related services. The company accounts directly for 20% of Vietnam's
oil production and half of its gas production. Its PetroVietnam Exploration Production
(PVEP) unit manages all upstream operations, while PV Oil is the main downstream
subsidiary and PV Gas is responsible for gas distribution. The company operates alone
or in partnership with IOCs under JOC contracts, similar to a PSC, in which a
Vietnamese legal entity acts as an agent on behalf of the contracting parties, with each
party contributing staff to the operating company. However, there are plans to offer
IOCs sole control of the fields.
The 50:50 JV with Zarubezhneft - Vietsovpetro - accounts for about a third of the
country's crude production, operating the flagship Bach Ho field in Block 09-3, as well
as Blocks 09-1 and 05-2; sites of the White Tiger, Dragon and Dai Hung fields. In 2008,
PetroVietnam launched three new oil fields: Phuong Dong, Ca Ngu Vang and Golden
Lion. The Bunga Orkid and Nam Rong (South Dragon)-Doi Mai fields were launched in
2009.
PetroVietnam, said in April 2012 that it had signed with South Korea's SK Holdings a
memorandum of understanding under which the firm may join PetroVietnam's energy
projects. PetroVietnam said in a statement that it encourages SK Holdings to participate
in the projects to develop coal-fired power plants as well as oil exploration and
production, and oil processing, it said in a statement.
A joint venture led by PetroVietnam has started production of natural gas at the Su Tu
Trang field at Block 15-1, reports Reuters. The block, which comprises five fields, is
located 50km offshore Vietnam in the Cuu Long Basin. The field is producing 5,000b/d
of condensate and 1.42mn standard cubic metres of natural gas. PetroVietnam owns a
Page 65
50% stake in the Cuu Long Joint Operating Company, working alongside partners
Perenco with 23.25%, Korean National Oil Corporation with 14.25%, SK Energy with
9% and Geopetrol with the remaining 3.5%.
On the last week of February 2013, Italy's Eni and PetroVietnam signed an agreement to
collaborate in assessing and exploring Vietnam's unconventional potential. So far, no
specific targets or details have been decided. While there are no widely available
estimates of unconventional potential in South East Asia, oil shows from tight reservoir
sands in the Cuu Long Basin offshore southern Vietnam have stoked optimism that the
region holds unconventional oil potential.
Total revenue for PetroVietnam and its affiliates in 2013 soared to a combined
VND762.86 trillion (US$36.33bn), 18% higher than the target set for the year. The group
contributed VND195.4trn to the State budget, which was 4.5% higher than the previous
year and was 31.5% higher than the target for that year. Total pre-tax profit climbed to
VND62.8trn, an increase of 27.5% y-o-y. The company in 2013 produced 16.71mn
tonnes of oil (334,200b/d) and 9.8bn cubic metres (bcm) of gas.
PV Gas, a subsidiary of PetroVietnam, is offering overseas investors a 49% in its
planned liquefied natural gas (LNG) receiving terminal at Son My in Binh Thuan
Province, reports Platts, citing a PetroVietnam investment document. The company
stated that it is discussing the matter with several commercial counsellors at European
embassies in Hanoi. The engineering, procurement and construction (EPC) bidding
process for the terminal is scheduled to take six-to-twelve months and conclude within
45 months of awarding the contract.
General Petroleum Exploration Company (PVEP), a subsidiary of PetroVietnam, has
assumed operatorship of the Song Doc oilfield at block 46-02 in the Malay-Tho Chu
Basin offshore Vietnam. The move comes after the other two partners in the Song Doc
oilfield project, Canadian exploration company Talisman Energy and Malaysia's
Petronas, withdrew and formally handed over the project to PVEP on November 24
2014. The reason for the transfer was not disclosed by any of the three parties.
Financial Data
Gross revenue:
Operational Data
VND763trn (2013)
VND332trn (2011)
VND241trn (2010)
VND265trn (2009)
VND280trn (2008)
Year established: 1975
No. of employees: 17,000
334,200b/d (2013)
Page 66
Page 67
Rosneft Vietnam
SWOT Analysis
Strengths
Opportunities
Threats
Company Overview
Prior to the disposal of its Vietnamese assets to TNK-BP, BP had been active in oil and
gas exploration and production (E&P), the production and distribution of lubricants and
liquefied petroleum gas (LPG), crude supplies for the refining industry, the provision of
gas oils and jet fuels, and the distribution of chemical and solar power systems. The
company's key investment, prior to the TNK-BP divestment, was the US$1.3bn Nam
Con Son Gas project, which involves the offshore Lan Tay (West Orchid) and Lan Do
(Red Orchid) gas fields in Block 06.1. BP held 33.3% in the project and worked in
partnership with ONGC Videsh (OVL) and PetroVietnam. These two fields contain
estimated reserves of 58bn cubic metres (bcm) and are producing 4.8bcm on average.
Gas from the Nam Con Son fields is transported via a 400km pipeline to two power
plants in the Ba Ria-Vung Tau province. BP operated the pipeline in partnership with
Page 68
PetroVietnam and ConocoPhillips (which sold its share to Perenco). BP had a 33.33%
interest in the Phu My 3 power plant, which is supplied by Nam Con Son.
Strategy
TNK-BP has now been absorbed into Russia's Rosneft, and early signs suggest that
Rosneft would like to strengthen its role in Vietnam, using TNK as the main vehicle.
Prior to the merger, Rosneft had no strong international presence, so it is expected to
continue on the path chosen by the former BP Vietnam business. However, if Rosneft
needs to allocate all management time and resources to its greatly expanded Russian
portfolio, there may be a change of direction or even of ownership.
During the Vietnamese prime minister's planned visit to Russia in May 2013,
PetroVietnam and state-controlled Rosneft plan to sign a new petroleum contract and
an agreement for cooperating in oil projects in onshore and offshore areas of Russia,
PetroVietnam said. Rosneft has been in negotiations with PetroVietnam over
cooperation for some time, and since completing acquisition of TNK-BP earlier in 2013,
has controlled TNK-BP's Vietnamese subsidiary TNK Vietnam. PetroVietnam did not
elaborate on the petroleum contract, but a source familiar with the matter said that TNK
Vietnam had bid for one of the nine offshore blocks that PetroVietnam offered in a 2011
bidding round.. PetroVietnam and Rosneft have agreed that Rosneft would expand its
oil and gas operations in Vietnam and supply the country with crude oil through longterm contracts, PetroVietnam's statement added.
Rosneft and PetroVietnam in November 2013 signed an agreement on basic terms for a
geological survey, hydrocarbon exploration and production in the Pechora Sea. The
agreement was signed by Igor Sechin, Rosneft President, and Dr. Do Van Hau,
President and CEO of PetroVietnam. The parties also signed a memorandum of
understanding for Rosneft's potential acquisition of a stake in the production sharing
agreement (PSA) for Block 15-1/05 in the Vietnamese offshore area.
Rosneft is considering shipping liquefied natural gas LNG) to Vietnam the Kommersant
daily reported in November 2013. Rosneft and Novatek, after lobbying to win the right
to export export LNG from Russia, are expected to get approval in 2014. Rosneft has
teamed up with ExxonMobil to build an LNG plant on the Pacific Island of Sakhalin with
initial capacity of 5mn tonnes per annum (tpa). Citing sources in the Russian delegation,
Kommersant said that Rosneft was considering shipping around 1mn tpa annually to
Vietnam from the US$15bn plant due to be launched in 2018.
Market Position
BP had been active in oil and gas E&P, the production and distribution of lubricants and
LPG, crude supplies for the refining industry, the provision of gas oils and jet fuels, and
the distribution of chemical and solar power systems. The company's key investment,
prior to the TNK-BP divestment, was the US$1.3bn Nam Con Son Gas project, which
involves the offshore Lan Tay (West Orchid) and Lan Do (Red Orchid) gas fields in Block
06.1. BP held 33.3% in the project and worked in partnership with ONGC Videsh (OVL)
and PetroVietnam. These two fields contain estimated reserves of 58bcm and are
Page 69
producing 4.8bcm on average. Gas from the Nam Con Son fields is transported via a
400km pipeline to two power plants in the Ba Ria-Vung Tau province. BP operated the
pipeline in partnership with PetroVietnam and ConocoPhillips (which has since sold its
share to Perenco). BP had a 33.33% interest in the Phu My 3 power plant, which is
supplied by Nam Con Son.
TNK-BP said in April 2012 that it had successfully drilled two wells on the Lan Do field
in offshore Vietnam. The field is located 28km east of Lan Tay Platform in Block 06.1,
where natural gas and condensate are produced for power generation in Vietnam. Gas
production from Lan Do is expected to bring 2bcm of gas annually to sustain Block
06.1's current production of 4.7bcm, the company said. TNK-BP said in October 2012
that it had started gas production at the Lan Do field.
Operational Data
Gas Production
Company Details
0.48bcm (2012)
0.71bcm (2011)
0.80bcm (2010)
0.65bcm (2009)
0.63bcm (2008)
0.85bcm (2007)
Year established: 1989
No. of employees: 700
TNK-BP
Villa A15 An Phu
District 2
Ho Chi Minh City
Vietnam
Page 70
Petronas Vietnam
SWOT Analysis
Strengths
Weaknesses
Opportunities
Threats
Company Overview
Strategy
The company has been developing a number of deals in Vietnam and looks set to
continue in this vein, accumulating a sizeable portfolio. In particular, Petronas is
focusing on the development of production capacity.
International operations in the Philippines, Vietnam and Thailand by petroleum
marketing company Petronas Dagangan are expected to contribute between 5% and
8% to its income stream in five years. These recently acquired businesses currently
contribute less than 1% to the net income of the company. To support these
Page 71
international ventures, the domestic oil marketing arm of national oil and gas company
Petronas has also raised its allocation for capital expenditure (capex) to MYR700mn.
The petrochemicals arm of Petronas will sell its stake in Vietnam's Phu My Plastics and
Chemical Company (PMPC) to Japan's Asahi Glass Co and Mitsubishi Corporation.
Petronas Chemicals Group said in a stock exchange statement that the divestment of
93.1% of PMPC was part of a plan to discontinue its vinyl business and strengthen its
asset portfolio. Petronas Chemicals did not disclose the financial details of the
transaction but said the sale would be completed by the second quarter of 2014.
Market Position
Petronas brought the Topaz (Block 02) and Pearl (Block 01) oil fields on-stream in
November 2010. Topaz has been producing 1,700b/d at launch, while Pearl yielded
2,500b/d. Petronas holds 85% in both fields, with the remainder held by PetroVietnam.
In September 2010, Petronas announced a discovery at the Ham Rong-2X well off the
coast of Hai Phong. The well is in Block 102 and 106 in the Song Hong Basin and initial
estimates suggested it could produce 6,300 barrels per day (b/d) of oil and 0.22mn
cubic metres per day (Mcm/d) of gas. Petronas Carigali is the operator of the block with
a 50% interest, while partners ATI Petroleum and Singapore Petroleum own 20% each
and PetroVietnam owns the remaining 10%. Although hydrocarbons were also
discovered in earlier drillings of the Yen Tu-1X well and the Ham Rong-1X well, no
concrete plans for development and production of the block had been made as of
January 2011.
Petronas Dagangan in December 2012 announced the completion of its acquisition of
Petronas Vietnam (PVL) and Thang Long LPG (TLLCL) in Vietnam in accordance with
the terms of the share sale and purchase agreements dated June 1 2012. In a
statement it said following the completion of the acquisition, both PVL and TLLCL will
be held by PDB via its newly incorporated and wholly-owned investment holding
company, PDB (Netherlands) B.V.
PDB Managing Director and Chief Executive Officer, Aminul Rashid Mohd Zamzam,
said: 'Following the completion of this strategic corporate exercise, PDB will fully
integrate its domestic and regional operations.
'The focus moving forward is to roll out the various growth initiatives over the next 12
months, focusing on nurturing and strengthening the newly acquired companies.
'We have already put in place the business plans to ensure our focus and strategies
moving forward are aligned.'
As part of the company's regional expansion strategy, PDB will undertake targeted
investments to propel future growth for these newly acquired companies, PDB added.
PDB is the principal domestic marketing arm of Petronas, which holds 69.86% of its
equity.
General Petroleum Exploration Company (PVEP), a subsidiary of state-owned energy
firm PetroVietnam, has assumed operatorship of the Song Doc oilfield at block 46-02 in
Page 72
the Malay-Tho Chu Basin offshore Vietnam. The move comes after the other two
partners in the Song Doc oilfield project, Canadian exploration company Talisman
Energy and Petronas, withdrew and formally handed over the project to PVEP on
November 24 2013. The reason for the transfer was not disclosed by any of the three
parties.
Operational Data
Company Details
Oil Production
12,650b/d (2008)
Petronas Building
No 170 Hai Ba Trung Street
District 1
Ho Chi Minh City
Vietnam
Page 73
Zarubezhneft/Vietsovpetro
SWOT Analysis
Strengths
Opportunities
Threats
Company Overview
Zarubezhneft was the first foreign company to operate in Vietnam's post-COMECON oil
industry, forming the 50:50 Vietsovpetro joint venture (JV) in 1981. Originally set to
expire in 2010, the JV was extended indefinitely in October 2008. Vietsovpetro became
a limited company in January 2011, with Zarubezhneft holding 49% and PetroVietnam
51%. Vietsovpetro operates seven fields in the South China Sea. Its main producing
assets are the Bach Ho (White Tiger), Mo Rong (Dragon) and Gau Lon (Big Bear) fields.
With a 50% stake, Zarubezhneft is also a majority partner in VRJ Petroleum, alongside
PetroVietnam (35%) and Japan's Idemitsu Kosan (15%).
Strategy
Vietsovpetro aims to produce 5.1mn tonnes (102,000b/d) of crude oil in 2014, down
7.3% from 2013, it said in January 2014. The company's annual oil output has been on
the decline in recent years given falling production from aging fields, including the
flagship Bach Ho in block 09-1. Vietsovpetro produced 5.5mn tonnes in 2013, down
Page 74
from 6.1mn tonnes in 2012. Of the 5.1mn tonnes planned for 2014, about 3.9mn is
expected to come from the Bach Ho field, 839,600 tonnes from Rong, 139,700 tonnes
from Nam Rong-Doi Moi, 117,100 tonnes from Gau Trang and 93,800 tonnes from Tho
Trang. The fields are located in blocks 09-1 and 9-3 offshore southern Vietnam.
Vietsovpetro had earlier announced plans to increase its oil output from around
130,000boe/d in 2010 to 140,000boe/d in 2015, reversing a long-term production
decline trend. Vietsovpetro currently accounts for around 40% of Vietnamese crude oil
production thanks largely to the highly mature Bach Ho (White Tiger) field.
During a meeting between PetroVietnam Chairman Phung Dinh Thuc and
Zarubezhneft's General Director Sergei Kudryashov, the two companies agreed to
establish a Russia-based joint venture to operate in three offshore blocks in the Caspian
and Pechora seas as well as new blocks on Vietnam's continental shelf, PetroVietnam
said. The two sides plan to sign an agreement when Vietnamese Prime Minister Nguyen
Tan Dung visits Russia, the statement said. The Vietnamese government said he would
make the trip in May 2013 but released no other details. PetroVietnam and
Zarubezhneft would also sign a deal during Dung's visit to establish a drilling services
joint venture operating in offshore Russia and Vietnam, PetroVietnam said.
Zarubezhneft has confirmed that it is to remove its Songa Mercur drilling rig from its
operations in Cuba and move it to Vietnam, according to Rigzone. The rig was deemed
of better use to Zarubezhneft elsewhere, due to operations problems with the Cuban
exploration well and the onset of the Caribbean hurricane season. The rig will now be
moved to another prospect in Vietnam; however, Zarubezhneft did state that it expects
drilling to continue in Cuba at some point.
Market Position
Following Vietnam's entry into the Soviet trading bloc COMECON in 1978, Zarubezhneft
became the first foreign company to operate in its oil industry, forming the 50:50
Vietsovpetro JV in 1981. Originally set to expire in 2010, the JV was extended
indefinitely in October 2008. Reflecting a gradual shift in power, under the new terms
Vietsovpetro became a limited company in January 2011, with Zarubezhneft holding
49% and PetroVietnam 51%.
Vietsovpetro operates seven fields in the South China Sea. Its main producing assets
are the Bach Ho (White Tiger), Mo Rong (Dragon) and Gau Lon (Big Bear) fields.
Although most of the fields have gas-capture facilities, direct gas involvement is limited.
Given Vietnam's significant upside gas potential, this poses a threat to Zarubezhneft's
long-term position in the country's energy sector.
With a 50% stake, Zarubezhneft is also a majority partner in VRJ Petroleum, alongside
PetroVietnam (35%) and Japan's Idemitsu Kosan (15%).
Financial Data
Page 75
Operational Data
Oil Production:
65,500b/d (2009)
77,500b/d (2008)
87,500b/d (2007)
Gas Production:
Company Details
0.82bcm (2009)
Zarubezhneft
Page 76
Other Summaries
Vietgazprom
Vietsovpetro's gas counterpart is the 50:50 Vietgazprom joint venture (JV) formed in
2000 between PetroVietnam and Zarubezhneftegas, a subsidiary of Russian state gas
company Gazprom. Originally focused on exploration, in 2006 the Russian and
Vietnamese authorities announced plans to transform Vietgazprom into a fully
integrated gas company. The company holds a sizeable prospective portfolio and has
recently been increasing its drilling activity.
In February 2009, Vietgazprom received a licence to explore and develop blocks 129,
130, 131 and 132. The licence will be valid for 30 years, with the possibility of a fiveyear extension. Under the agreement, Vietgazprom has committed to drill at least two
wildcat wells and carry out a 2D-seismic survey within a three-year period. Gazprom
announced that it would bear the initial costs of exploration.
Origin Energy
Australia's Origin Energy has announced that its 121-CV-1X exploration well at Block
121 of its production sharing contract, offshore Vietnam, has reached its total measured
depth of 3,750 metres. However, testing at the well proved disappointing and it has
since been plugged and abandoned after Origin encountered only minor gas indications
in the targeted Oliogocence sandstones. The 121-CV-1X well was drilled using the
Ocean General (mid-water semisub) rig, which will now be moved to another block in
the Phu Khanh Basin.
Perenco
French independent Perenco owns three subsidiaries in Vietnam. The subsidiaries hold
a 23.25% participating interest in Block 15-1, a 36% participating interest in Block 15-2
and a 16.3% participating interest in the Nam Con Son Pipeline. Those stakes were
previously owned by US-based ConocoPhillips. Gross production is 75,000 barrels per
day (b/d).
Located 160 miles offshore south east of Ho-Chi-Minh City, Block 15-1 is in the Cuu
Long Basin. Production from its Su Tu Den Field began in late 2003. Su Tu Den crude
oil is processed and stored in the 1mn bbl Cuu Long Thai Binh FPSO vessel. Production
from the Su Tu Vang Field began in 2008. First production on the Su Tu Den Northeast
Field occurred in May 2010.
Block 15-2 contains the Rang Dong Field also in the Cuu Long Basin. Rang Dong crude
oil is stored in the MV-17 FSO, where it is offloaded to tankers for export.
The Nam Con Son Pipeline is a 700-MMCFD, 244 mile transportation system linking
natural gas supplies from the Nam Con Son Basin to markets in southern Vietnam. The
infrastructure consists of a 26-inch diameter, 227 mile offshore pipeline segment
delivering wet gas to the gas plant located at Dinh Co, Ba Ria-Vung Tau province. The
gas is conditioned to meet sales specifications and is redelivered via a 30-inchdiameter, 17 mile onshore pipeline segment to the Phu My gas distribution centre.
Page 77
A joint venture led by PetroVietnam has started production of natural gas at the Su
Tu Trang field at Block 15-1, reports Reuters. The block, which comprises five fields, is
located 50km offshore Vietnam in the Cuu Long Basin. The field is producing 5,000b/d
of condensate and 1.42mn standard cubic metres of natural gas. PetroVietnam owns a
50% stake in the Cuu Long Joint Operating Company, working alongside partners
Perenco with 23.25%, KNOC with 14.25%, SK Energy with 9% and Geopetrol with the
remaining 3.5%.
Lukoil
In October 2011, Russia's Lukoil said it received Vietnamese government approval for
its purchase of a 50% stake in a Vietnamese offshore block estimated to hold 180mn
tonnes of oil equivalent. In April 2011, the company agreed to a production sharing
agreement for the Hanoi Trough-02, taking half of the South China Sea project from
Quad Energy, which kept the other half. The block, which has been explored since
2007, is now home to 'a number of identified prospects', Lukoil said. The company was
to be the operator of the project and planned to drill three exploration wells.
Idemitsu Kosan
After years of deliberation, it has finally been confirmed that the Nghi Son refinery in
Vietnam will proceed with construction. On January 15 2013, Japan's Idemitsu
announced that it has approved a US$9bn investment required to build the 200,000b/d
refinery, which will be Vietnam's second after Dong Quat. Construction is due to begin
in Q213 and the plant is scheduled to come online in 2017.
Idemitsu holds a 35.1% stake in the project and Kuwait Petroleum, via its marketing
arm Kuwait Petroleum International, holds the other 35.1%. The remaining interest is
held by state-owned PetroVietnam (25.1%) and Mitsui Chemicals (4.7%). A consortium
formed by Chiyoda Corporation, JGC Corporation, Technip, GS Engineering and SK
Engineering has been awarded the engineering, procurement and construction (EPC)
contract to build the plant.
Nghi Son's supplies are much needed by Vietnam, whose oil consumption has
expanded beyond total fuel production growth. The 130,500b/d Dong Quat refinery
came into operation in 2009, but the country still imports more than half of its required
fuel needs. If Nghi Son is operational by 2017 as planned, in 2018 we estimate that its
net import requirement could fall to about 23% of total consumption.
In the upstream segment, Idemitsu is an equity holder in exploration licence 05-1 and
has 15% in the VRJ exploration venture where it is partner to PetroVietnam and
Zarubezhneft. The VRJ exploration venture saw block 9-3 come on-stream in February
2010, producing about 20,000b/d.
KNOC has been involved in Vietnam's energy sector since 1992 and holds stakes in two
producing assets: blocks 15-1 (14.25%) and 11-2 (39.75%).
KNOC and PetroVietnam started producing gas from Block 11-2 in December 2006.
The field had initial output of 1.34bn cubic metres (bcm) and is thought to be capable of
Page 78
producing around 24.2bcm of gas and 23mn barrels (bbl) of condensate over its
lifespan. The US$300mn block covers two gas condensate developments, Rong Doi
(Twin Dragon) and Rong Doi Tay (Twin Dragon West), 280km offshore Ba Ria-Vung Tau
province. Under the terms of a 2002 agreement, gas will be purchased by PetroVietnam
until 2028 and all the output will be piped to a major power complex. Gross production
from Block 11-2 is around 1.4bcm. Block 11-2 was the first overseas operating project
of KNOC.
A joint venture led by PetroVietnam has started production of natural gas at the Su
Tu Trang field at Block 15-1, reports Reuters. The block, which comprises five fields, is
located 50km offshore Vietnam in the Cuu Long Basin. The field is producing 5,000b/d
of condensate and 1.42mn standard cubic metres of natural gas (Mcm). PetroVietnam
owns a 50% stake in the Cuu Long Joint Operating Company, working alongside
partners Perenco with 23.25%, KNOC with 14.25%, SK Energy with 9% and Geopetrol
with the remaining 3.5%.
Chevron
Chevron is the operator in two production sharing contracts (PSCs) in Vietnam. They
are in the northern part of the Malay Basin, off the coast of south-west Vietnam.
Chevron has a 42.4% interest in a PSC that includes Blocks B and 48/95.Chevron also
has a 43.4% interest in a PSC that covers Block 52/97. In 2012, it drilled two
exploratory wells in Block 52/97. Both were successful.
The Vietnam Block B Gas Project is designed to deliver the natural gas from Chevron's
PSCs in the Malay Basin to existing and proposed power plants in southern Vietnam.
The project includes installation of wellhead and hub platforms, a floating storage and
offloading vessel, field pipelines, a living-quarters platform, a central-processing
platform and a pipeline to shore. The targeted maximum total daily production is 490mn
cubic feet of natural gas and 4,000bbl of condensate. A final investment decision for the
development is pending resolution of commercial terms.
In conjunction with the offshore development, the company has a 28.7% non-operated
working interest in a pipeline project that would deliver natural gas from the
development to utility companies in southern Vietnam.
Chevron Lubricants Vietnam Limited manufactures and sells motor oils and marine,
industrial and specialty products through 60 distributors to more than 12,000 retail
outlets nationwide. It also sells directly to large industrial and marine customers. Its
lubricating oil blending plant is in Haiphong, in northern Vietnam.
ONGC Videsh (OVL), the international subsidiary of Indian state-run oil and gas
company ONGC, is considering acquiring a stake in Chevron's Block B gas project in
Vietnam. Chevron, which owns a 42.38% stake in the US$4.3bn Block B, is seeking
expression of interests from global companies ready to farm-in or purchase a stake,
according to unnamed sources. Vietnam's block B is estimated to have 0.113trn cubic
metres of total inplace reserves, of which 63% are recoverable reserves.
Page 79
Talisman Energy
Canadian independent Talisman Energy holds a 30% interest in Block 46/02 and in the
Truong Son Joint Operating Company (JOC) which operates the Block. Block 46/02 lies
in the Malay - Tho Chu Basin, adjacent to PM-3 CAA and Block 46-Cai Nuoc. Talisman
also holds a 60% interest in Block 15-2/01 and in the Thang Long JOC, which operates
the Block. Block 15-2/01 lies in the Cuu Long Basin, the predominant oil producing
basin in Vietnam. The company also holds a 49% operated interest in Blocks 133 and
134, 40% in Blocks 135 and 136, and 40% in Block 05-2/10 in the Nam Con Son Basin.
In 2012, Talisman reached a farm-in agreement with Mitra Energy Limited to acquire a
35% interest in Blocks 45 and 46/07 adjacent to PM-3 CAA in the Malay-Tho Chu
Basin. This agreement has been approved by PetroVietnam and is now awaiting
government approval for the amended investment licences.
In 2012, Vietnam production averaged 1.9mn b/d, with 1.3mn b/d from Block 46/02,
accounting for approximately 1% of Southeast Asia production. In December 2011,
Talisman sanctioned the HST/HSD development project in Block 15-2/01. The
development, which will be tied into the adjacent Block 16-1 facilities operated by
Hoang Long JOC to the south of Block 15-2/01, is progressing on schedule and on
budget, with two jackets now installed and the drilling rig on location at HST. Pipeline
tie-ins and all subsea construction work was completed in 2012 and development
drilling for the four HST wells is progressing according to schedule. First production is
planned for the second half of 2013.
In 2012, Talisman drilled the exploration well, Ngoc Thac 4-1X on Block 05-2/10, which
was plugged and abandoned without encountering hydrocarbons. A second exploration
well in the same block, Thac Anh 3-1X, was drilled and resulted in a non-commercial
gas discovery. In addition, Talisman acquired 3D seismic on Blocks 135 and 136.
Talisman Energy has announced that it has brought online its Hai Su Trang and Hai Su
Den development offshore Vietnam, Rigzone reports. The company expects to achieve
gross production of 15,000b/d from the deepwater field. Paul Blakelely, the company's
executive vice president for Asia Pacific, said the work had been completed ahead of
schedule and under budget, the project only having been sanctioned in late 2011.
Talisman Energy has discovered oil at its CRD-3X appraisal well in the Ca Rong Do field
offshore Vietnam, according to Australia-based joint venture partner Pan Pacific
Petroleum. Talisman conducted drill stem flow testing on three key Miocene reservoirs,
with the first test encountering 4,100b/d of oil and 0.055mn cubic metres (Mcm) of gas
per day. The second test intersected 2,750b/d of oil and 0.021Mcm of gas per day,
while the third encountered 1,161b/d of oil plus 0.0019Mcm of gas per day.
General Petroleum Exploration Company (PVEP), a subsidiary of PetroVietnam, has
assumed operatorship of the Song Doc oilfield at block 46-02 in the Malay-Tho Chu
Basin offshore Vietnam. The move comes after the other two partners in the Song Doc
oilfield project, Talisman Energy and Malaysia's state-owned Petronas, withdrew and
Page 80
formally handed over the project to PVEP on November 24. The reason for the transfer
was not disclosed by any of the three parties.
Premier Oil
UK-based Premier Oil has announced that it has sold 100% of shares in its subsidiary
Premier Oil Vietnam South (POVS) to an undisclosed buyer for an initial US$100mn. The
deal gives the buyer control of POVS's 30% operated interest in Block 07/03, offshore
Vietnam, which houses the Ca Rong Do oil and gas discovery and the Ca Duc (Silver
Sillago) exploration prospect.
The company acquired interests in the Nam Con Son basin in 2004 and, in 2006, it
made the Chim So oil discovery. Premier now has exploration, development and
production activities across two licences in Vietnam. Its interests include the Premieroperated Chim Sao field, which Premier brought on-stream in the second half of 2011;
the Dua project, which will be developed as subsea tie back to Chim Sao; and Ca
Rong Doh, a future development project. In addition, it continues to explore across its
existing acreage and notable successes include the Chim Sao North West discovery
and the successful appraisal of CRD in 2011.
A field development plan for Chim So was submitted to the Vietnamese Government
and approved in 2008. First oil production from Chim So was achieved in October
2011, with first production from Dua expected in 2014. Output from Chim So is
expected to plateau at around 25,000b/d, at which time gas production will be
approximately 25mn cubic feet per day.
Commercial development of the CRD accumulation is now under review, along with
further investigation of the exploration potential of the rest of Block 07/03. Premier's
partners in the block are VAMEX and Pearl Energy. Detailed subsurface and facilities
work was undertaken to define the development plan for the Dua field during 2010 and
the Outline Development Plan for the project, a tie-in to the Chim Sao field, was
approved by the government of Vietnam in December 2011. First oil is expected during
2014.
In July 2012, Premier agreed to farm-in to the Origin Energy-operated Block 121 for a
participating interest of 40%. Premier will pay its participating interest share in the
drilling of the high-risk Ca Voi prospect which will spud in the second quarter of 2013.
Block 121 lies in the northern part of the frontier Phu Khanh Basin. The prospectivity
centres on the untested Oligocene play fairway, which Premier recognises as being
geologically similar to that of the Cau formation which it has successfully explored in
Blocks 12W and 07/03 in the Nam Con Son Basin.
During the Chim So development drilling programme, the CS-N2P well intersected an
estimated 15 metres of net oil bearing sandstones in the fault terrace to the north west
of the Chim Sao field. This was subsequently appraised by the CS-N1P development
well which intersected an estimated 89 metres of net oil bearing sands within a stacked
sequence of Upper Dua sandstones.
Page 81
The Chim Sao North West appraisal well, CS-3X, in Vietnam Block 12W in August 2012
reached a total depth of 4,235 metres. The well has been plugged and abandoned after
encountering oil shows in the Middle Dua sands. The appraisal well was drilled to
determine whether the Chim Sao North West discovery extended into a separate fault
segment to the north. The well targeted the Upper and Middle Dua sands. While 135
metres of sandstone reservoir were penetrated in the Upper Dua interval there was no
indication of hydrocarbons. In the Middle Dua interval 165 metres of sands were drilled,
but only oil shows were encountered.
Australian energy company Pan Pacific Petroleum (PPP) has received an update from
the operator of Block 07/03 that drilling of the CRD-3X and sidetrack appraisal wells,
offshore Vietnam, has been completed. Logging at the wells, which were drilled using
the Ocean General semi-submersible drilling rig, indicated 46.1 metre (m) net oil pay
and 49.5m net gas pay. Premier Oil Vietnam South is the operator of the well with a
30% stake, along with Vamex with a 25% stake, Mubadala Petroleum with a 25% and
PetroVietnam Exploration and Production Corporation with 15%.
Gazprom
Gazprom, in association with PetroVietnam, is planning to develop the 05.2 and 05.3
blocks in the South China Sea. The project, in which Gazprom will take a 49% interest,
is to be carried out under a PSA. The blocks hold two discovered gas and condensate
fields, dubbed Moc Tinh and Hai Thach, with total reserves of 55.6bn cubic metres
(bcm) of gas and 25.1mn tonnes of condensate.
In a meeting between PetroVietnam chairman Thuc and his Gazprom counterpart,
Alexey Miller, the two sides paid special attention to their potential cooperation in the
area of natural gas use as a motor fuel, Gazprom said in a statement during April 2013.
They discussed progress on joint projects offshore Vietnam, the statement said, noting
that exploration activities in blocks 112 and 129-132 were successful. Gazprom and
PetroVietnam also identified ways to cooperate in LNG marketing, including the
possible conclusion of a long-term LNG supply contract, Gazprom said. They signed a
memorandum of understanding in July to supply Vietnam with Russian LNG.
Separately, PetroVietnam and Gazprom's subsidiary, Gazprom Neft, plan to sign a deal
to cooperate in the upstream sectors of Vietnam and Russia, invest in the
petrochemical and refining sectors, and sell petroleum products in Vietnam,
PetroVietnam said. PetroVietnam has a 49% stake in Russia-based GazPromViet, and
Gazprom holds the remaining stake. Gazprom, meanwhile, holds a 49% share in
VietGazprom JV in Vietnam, with PetroVietnam controlling the remainder.
Soco International
Page 82
Soco has entered a conditional agreement with Lizeroux Oil & Gas to acquire the latter's
20% stake in Vietnam-based Soco Vietnam in a deal worth US$95mn. Soco
International is to pay the consideration amount out of its existing cash reserves. The
acquisition will give complete management control of Soco Vietnam to Soco
International. Soco Vietnam owns a 28.5% working interest in the Te Giac Trang field
and a 25% working interest in the Ca Ngu Vang field. Soco International has paid
Lizeroux's share of all the expenditure made by Soco Vietnam.
The Te Giac Trang H4 wellhead platform commenced production a month ahead of
schedule in July 2012, increasing field production to average approximately 50,000b/d
since start up; peak production of over 60,500b/d to date as the FPSO capacity limits
are gradually tested.
Soco has said that production from its Te Giac Trang (TGT) field offshore southern
Vietnam remains on target and is currently delivering at a rate of between 52,000 and
55,000b/d, according to Offshore. The partners are now planning to undertake further
drilling activity at TGT and are looking to dig three to four infill wells and an H5 step-out
appraisal well over the course of 2013. TGT stretches over 13km and features more
than 50 clastic Miocene and Oligocene reservoir intervals. Estimates suggest that it
holds anywhere between 466mn and 958mn bbl of oil, with potentially another 152mn
bbl yet to be discovered.
Tests of the floating production, storage, and offloading vessel on Te Giac Trang (TGT)
oil field offshore Vietnam have confirmed production capacity beyond the 55,000b/d
minimum contractual rate, reports Soco. Hoang Long Joint Operating Co, the operator,
has completed the first phase of a multistage test of the FPSO, achieving production of
more than 60,000b/d.
The tests 'fully support our belief that with only minor modifications the FPSO should
comfortably be able to handle volumes of around 70,000b/d,' said Ed Story, Soco
president and chief executive officer. 'This gives us considerable confidence that the
TGT field production levels can be maintained at a rate of about 55,000b/d.' After
modifications to the low-pressure separator system, a new phase of testing will process
more than 60,000b/d.
Total
French major Total entered Vietnam's upstream segment in 2007 and moved
downstream in 2008 as part of its diversification strategy in the Asia Pacific region. In
August 2007, Total was awarded a 35% interest in a PSC to explore Block 15-1/05 in
the Cuu Long Basin. Exploration was to be undertaken in conjunction with
PetroVietnam (40%) and SK Energy (25%). The first phase of the exploration
programme involved 800sq km of 3D seismic and drilling two wells. The first well hit oil
at the Lac Da Nau prospect in November 2009; the well tested at 4,300b/d of 44 API
oil. In October 2010, Total reported another discovery at the block with the Lac Da Vang
exploration well. The well flowed 3,500b/d of API 43 crude during production testing.
Page 83
In March 2009, Total signed a PSC with PetroVietnam for exploration blocks DBSCL-02
and DBSCL-03, located onshore the Mekong Delta. Total will operate the blocks with a
75% interest, while the state company will hold the remaining 25%. Under the deal, the
first phase of exploration will cover the acquisition of 2D seismic on the blocks, which
cover 14,850sq km and 13,800sq km respectively.
Petrolimex
Petrolimex is the country's dominant fuels retailer, boasting around 6,000 outlets and a
60% market share. Under privatisation proposals announced in early January 2009, the
government is planning to sell 25% of the company, although the timeframe is
uncertain. Petrolimex is run by the Ministry of Trade and is one of the largest companies
in Vietnam, with an estimated turnover of VND25trn (US$1.3bn) in 2008. Evaluating the
company is difficult given that it does not publish accounts, but analysts interviewed by
the Financial Times value it at US$1.0-1.5bn.
Although Petrolimex has an extensive distribution network and an established brand, it
is set to face growing competition from private firms as the liberalisation of the
downstream segment proceeds. In particular, the company's fuel import permits, the
source of its current dominant market position, will gradually lose their power as more
domestic refineries come on-stream. A lack of exposure to the burgeoning refining
sector is another source of weakness for the company.
Petrolimex has announced it plans to invest up to US$4.8bn in the construction of the
200,000b/d Nam Van Phong refinery. The company is also looking into a US$212mn
project to build an oil products import pipeline from China to help meet the country's
rapidly growing fuels demand.
Neon Energy
Independent Neon Energy signed a PSC with PetroVietnam for Block 120 in the Song
Hong Basin in January 2009. Under the deal, Neon was to hold a 100% participating
interest in the block but in April 2010 Kris Energy and Enovation Resources announced
they had farmed-in to the block. Under the new arrangement, Neon operates the block
with a 50% stake, Kris holds a 40% stake and Enovation holds the remaining 10%.
In January 2010, Neon was awarded its second permit in Song Hong, Block 105-110/4.
During the initial four-year exploration programme, the company plans to acquire 2Dseismic data and drill at least one well, with surveys to start in 2010. Neon will hold 90%
in Block 105-110/4 and PVEP the remaining 10%.
Neon Energy has accepted a binding offer from an undisclosed company that will see it
farm-out its stakes in Block 120 and Block 105-110/04 offshore Vietnam. Under the
terms of the farm-out agreement, the buyer will gain the stakes in return for covering the
cost of an expanded work programme across both blocks. Further financial details were
not disclosed. The transaction is subject to the approval of Petrovietnam and Vietnam's
government, and is expected to be completed in Q112. Neon will continue to hold a
material working interest in the blocks.
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Neon Energy has identified a new oil and gas prospect during an ongoing evaluation of
3D seismic data within the Eni Vietnam-operated block 120 offshore Vietnam. The
500sq km 3D seismic programme, which was concluded in mid-2012 with the objective
of delineating prospects close to the 120-CS-1X well, revealed an additional prospect,
Ca Ngu, in the block. The Ca Ngu prospect, together with Rua Bien and Ca Lang, is a
candidate for the first exploratory well.
Neon has posted a drilling update on its Cua Lo-1 exploration well, offshore Vietnam,
reporting that it has encountered gas in each of its upper three objectives, prior to
experiencing a 'kick' due to an over-pressured gas bearing formation at 2,568 metres
(m). The well has since been stabilised and plugged at a depth of 1,800m and will now
be sidetracked and drilled to a revised casing point just above the pressure zone, Oil
Voice reports. The company said it was encouraged by the discovery of hydrocarbons
and is awaiting the return of reservoir samples to better understand the formation.
Neon, as part of the Vietnam Block 120 joint venture, has selected the Ca Ngu prospect
for drilling, Scandinavian Oil-Gas Magazine reports. Petrovietnam has approved the
location. The prospect was identified by a 500 square kilometre 3D seismic programme
that was completed in 2012. The primary objectives are clastic reservoirs of Pliocene
age and the underlying carbonate reservoir of Miocene age.
Neon has announced a significant gas discovery at the Cua Lo-1 ST1 exploration well in
Block 105 PSC, offshore Vietnam. The operator of Cua Lo-1 ST1, Eni Vietnam, reached
a total depth of 2,867metres (m) on the well and is now completing wireline logging
operations. Eni also confirmed the discovery of an additional zone of interest at the
4.7Ma level. The four reservoirs, comprising 4.1Ma, 4.2Ma, 4.5Ma and 4.7Ma, show
good indications of gas over a total gross interval of around 150m. Eni Vietnam is the
operator of Block 105 PSC with a 50% stake.
Others
ExxonMobil said in October 2011 that it had found oil and gas off Vietnam's central
coast. Exxon said it drilled its second exploratory well off the coast of Danang City in
August 2011 and found hydrocarbons. A company spokesman said that data from the
well, located in an area known as Block 119, are being analysed. The company said the
first well it drilled in offshore Vietnam didn't encounter oil and gas.
ExxonMobil confirmed it had encountered additional hydrocarbons at the 118-Ca Voi
Xanh-3X well in Da Nang, Vietnam. The company added that it was determining its
business plans while analysing data from the well. ExxonMobil, which drilled the well
between May and July 2012, previously discovered additional hydrocarbons at the 118Ca Voi Xanh-2X well.
Vietnam-based oil and gas explorer and producer Hoang Long Joint Operating
Company (HLJOC) has completed testing of its TGT-10XST1 exploration well situated in
the H5 fault block of the Te Giac Trang field offshore Vietnam. The final test was
conducted at the TGT-10XST1 over an 88.6 metre (m) perforated interval in the Lower
Miocene Intra Lower Bach Ho 5.2 Upper and Lower sequence. The test revealed an
Page 85
average maximum flow rate of 5,156b/d of oil and 0.90Mcm per day of gas.
TGT-10XST1 exceeded all pre-test expectations and flowed at a combined peak rate of
16,500b/d of oil and 0.082Mcm of gas. The Te Giac Trang field is operated by HLJOC,
with partners PetroVietnam with 41% stake, Soco International with 30.5% and
Thailand's PTT with the remaining 28.5%.
Vietnam's offshore acreage plays host to several Australian players. Major gas company
Santos holds two offshore exploration licences: 55% of Block 101-100/04 in the
northern Song Hong Basin and 31% in the PSA for Block 12W-12E. In April 2009,
Santos spudded its first exploration well in Block 101-100/04. The Ha Mai-1 wildcat
was drilled to a depth of 41m. Santos works on the block alongside Singapore
Petroleum Company (SPC), a PetroChina subsidiary.
Singapore-based Kris Energy acquired a 33.3% stake in Block 06/94 in the Nam Con
Son Basin from British explorer Serica Energy in December 2009. Serica's decision to
exit Vietnam is likely to have been prompted by disappointing drilling results. Serica
originally intended to keep a 10% stake in the permit and sell the remaining 23.3% to
AWE. The deal, however, was terminated in August 2009 after the first wildcat on the
block came up dry. The other partners in the licence are Pearl Oil (33.34%) and Swedish
company Lundin Petroleum (33.33%).
South Korea's SK Energy holds equity in one producing asset and two exploration
licences. The company holds 9% in Block 15-1, which is operated by PetroVietnam
(50%). Gross output in 2009 was expected to average 7,700b/d. In exploration blocks
123 and 15-1/05, SK holds 20% and 25% respectively. A joint venture led by
PetroVietnam has started production of natural gas at the Su Tu Trang field at Block
15-1, reports Reuters. The block, which comprises five fields, is located 50km offshore
Vietnam in the Cuu Long Basin. The field is producing 5,000b/d of condensate and
1.42Mcm of natural gas. PetroVietnam owns a 50% stake in the Cuu Long Joint
Operating Company, working alongside partners Perenco with 23.25%, KNOC with
14.25%, SK Energy with 9% and Geopetrol with the remaining 3.5%.
Thailand's PTTEP has a gas producing asset in Block 9-2, with output reaching
20,000boe/d by end-2008. Its other asset, Block 16-1, is still in the exploration stage.
UK-based Salamander Energy holds two PSAs offshore southern Vietnam. It is the sole
owner of the Cuu Long River Delta Block 1 (DBSCL-01) and holds 60% in nearby Block
31, where PetroVietnam holds the remaining 40%. Salamander planned to undertake
geological and geophysical studies, and start exploration drilling in 2010. Salamander
failed to find significant volumes of hydrocarbons at its Tom Hum Xanh-1X well in Block
31 in the offshore Vinh Chau Basin. The company plugged and abandoned the well.
Japan's Nippon Oil holds three offshore licences in the southern Cuu Long Basin:
46.5% in Block 15-2, 35% in Block 05-1 and 40% in Block 16-2. Its first producing
Vietnamese asset came on-stream in Q308. Initial flow rates at the Phuong Dong field in
Block 15-2 were 10,000b/d. Nippon Oil aims to develop the block's potential further.
Salamander Energy has signed a deal to farm-out a 20% stake in Block 101-100/04
offshore Vietnam, reports EBR. The agreement has been signed with Japanese
Business Monitor International
Page 86
petroleum firm JX Nippon Oil & Gas Exploration. The block includes the Cat Ba oil
prospect, which Salamander planned to drill using the CB-1X exploration well in Q311.
Pearl Energy, a subsidiary of Abu Dhabi's Mubadala investment vehicle, holds two Nam
Con Son licences. It is the operator of Block 06/94 (33.3%) and holds a participating
interest in Block 07/03 (15%). In late June 2009, Pearl announced that its Tuong Vi-1X
wildcat on Block 06/94 was a duster.
Kuwait Petroleum International (KPI) is part of the JV building the US$6bn oil refining
and petrochemicals complex at Nghi Son, which was due for completion in 2013. The
scheme includes a 200,000b/d refining complex, which is one of many destined to be
built in the rapidly expanding Asian country.
Kuwait Foreign Exploitation Company (KUFPEC), the international arm of Kuwait
Petroleum Company (KPC), holds stakes in three exploration blocks: 51, 19 and 20. In
blocks 19 and 20 it has a 40% non-operating stake, working alongside Malaysian
explorer Mitra Energy (60%). Mitra is contractually committed to drill at least one well in
each block during the first three years of the licence period.
Italian major Eni has signed an agreement with Indian company Essar Energy to farm-in
to the latter's exploration block 114 in the Song Hong Basin offshore Vietnam. Eni will
acquire a 50% stake in and operatorship of the block, which covers about 5,900sq km.
The companies will undertake an exploration programme for the block, including a 3D
seismic survey and drilling two wells. The farm-in is subject to approval by the relevant
Vietnamese authorities. Eni signed two acquisition agreements to farm-in to the
exploration blocks 105-110/04 and 120 in the Song Hong Basin on June 25 2012.
On the last week of February 2013, Eni and PetroVietnam signed an agreement to
collaborate in assessing and exploring Vietnam's unconventional potential.
Eni has selected the Ca Ngu prospect as a candidate for an exploratory well to be
drilled on block 120 offshore Vietnam, according to partner Neon Energy. The prospect
has been chosen as a 'play finder' well, as the company believes it may discover
hydrocarbons at multiple levels. The prospect also offers an optimal combination of risk
versus reward, according to Ken Charsinsky, the managing director of Neon Energy.
The Ca Ngu-1 exploration well, in water depths of 270 metres (m), will be drilled to a
total depth of up to 1,500m with the Songa Mercur semi-submersible.
Eni has encountered gas shows while drilling the Cua Lo-1 exploration well in the Song
Hong basin offshore Vietnam, according to partner Neon Energy. The discovery was
made within each of the upper three objectives at the well prior to experiencing a 'kick'
due to an over-pressured gas bearing formation at a depth of 2,568m. The well is
located in Block 105 and is being drilled by the Ensco 107 jack-up rig. The well has
been plugged to a depth of 1,800m, with Eni now planning to drill a sidetrack well to
bypass the over-pressured zone.
Eni Vietnam is to plug and abandon its Cua Lo-1 well in Vietnam. A drill stem test was
conducted on the well, located in Block 105-110/04 in the Song Hong basin, for five
Page 87
days. The test results confirmed poor reservoir deliverability, combined with high
carbon dioxide content, according to joint venture (JV) partner Neon Energy. The Cua
Lo-1 well was drilled to a total depth of 2,867 metres.
KrisEnergy has announced that partner Eni Vietnam has plugged and abandoned its Ca
Ngu 1 exploration well in block 120 offshore Vietnam. The move comes after Eni drilled
the well to a total depth of 1,290 metres (m) and discovered a hydrocarbon column of
15.2m. Though significant volumes of hydrocarbons were not discovered at the well, a
petroleum system is present in the region, according to KrisEnergy's director for
exploration and production Chris Gibson-Robinson. Eni Vietnam is the operator of the
well with a 50% interest.
Australian oil and gas explorer Pan Pacific Petroleum (PPP) reached a deal to buy a
15% stake in the Block 121 Production Sharing Contract, offshore Vietnam, from Origin
Energy. The transaction, which has already secured government approval, will allow
PPP to take part in the drilling of an attractive prospect via its subsidiary Pan Pacific
Petroleum Vietnam (121). The block covers an area of more than 8,000sq km. Following
the completion of the deal, Origin Energy will retain the operatorship of the block with a
45% stake, working alongside partners PPP with 15% and Premier Oil with the
remaining 40%.
Pan Pacific Petroleum is eyeing a three-well drilling campaign offshore Vietnam
following the acquisition of a 15% stake in the Block 121 production sharing contract.
The company acquired the stake from Origin Energy, which is the operator of the block
with a 45% stake, while Premier Oil owns a 40% stake. The company was to participate
in the drilling of the Ca Voi (Whale) prospect in the block, with the Ocean General semisubmersible rig scheduled to start drilling in May 2013. Additionally, the company will
join the drilling of two wells in Block 07/03 operated by Premier.
PPP has received an update from the operator of Block 07/03 that drilling of the
CRD-3X and sidetrack appraisal wells, offshore Vietnam, has been completed. Logging
at the wells, which were drilled using the Ocean General semi-submersible drilling rig,
indicated 46.1 metre (m) net oil pay and 49.5m net gas pay. Premier Oil Vietnam South
is the operator of the well with a 30% stake, along with Vamex with a 25% stake,
Mubadala Petroleum with a 25% and PetroVietnam Exploration and Production
Corporation with 15%.
Page 88
Regional Overview
Asia Overview
BMI View: There are four main themes that will characterise the Asian oil and gas industry over the
coming years: stronger growth in demand for gas than oil, the growing importance of liquefied natural gas
(LNG) to both producer and consumer markets, progress in shale gas exploration, and a challenging
downstream market for refiners in both regulated and free markets.
There are four main themes that will characterise the Asian oil and gas industry:
Gas will outperform oil in terms of both production and consumption growth.
Liquefied natural gas (LNG) development will remain a top priority, although we warn that growing cost
concerns will likely slow the pace of LNG development.
Rising consumption needs will continue to drive interest in unconventional exploration, although a
myriad of challenges - environmental and geological in particular - could prevent the region from quickly
replicating the US' shale gas success.
There is potential for overcapacity in the downstream market, as expansion continues to take place in
emerging Asia.
Gas Is Hot
Although BMI's Power team forecasts that coal will remain the dominant fuel for power generation in Asia,
some gravitation towards gas is underway as policies shift to reduce carbon emissions. Japan and South
Korea in particular will continue to be reliant on gas in their power sectors, as public aversion towards
nuclear power remains high. Meanwhile, China is seeking to increase the use of gas to 10% of its total
energy mix by 2020 (from 6% in 2012) in a bid to reduce reliance on coal, while India and Pakistan have
sufficient capacity to accommodate greater gas-fired capacity into their power grids. Other parts of South
East Asia, including the Philippines and Vietnam, are also looking to gas as feedstock for proposed power
projects.
Page 89
500
2022f
2021f
2020f
2019f
2018f
2017f
2016f
2015f
2014f
2013e
2012e
250
e/f=estimate/forecast. Source: EIA, Statistics Bureau Of Japan, FEPC, World Bank, BMI
Meanwhile, a slower rate of economic growth, as well as energy efficiency gains, will restrain growth in oil
demand. This will prove particularly true in China, where oil consumption growth is expected to slow from
about 4.8% in 2012 to 2.5% by the end of our forecast period in 2022. Downside risk to potential long-term
consumption growth exists as economic headwinds threaten to limit China's growth.
Page 90
2022f
2021f
2020f
2019f
2018f
2017f
2016f
2015f
2014f
2012
2013e
This will continue to see gas consumption growth outpace oil consumption growth in the region. Between
2012 and 2022, gas demand is expected to increase by 50.9%, compared to a slower (but still impressive)
rate of 24.0% over the same period for oil.
Page 91
That said, we acknowledge that success in increasing the use of gas in transportation - something which
China in particular has been pushing keenly - poses upside risk to our current forecasts for regional gas
consumption growth. Solving India and Pakistan's gas import infrastructure bottlenecks could also further
boost overall gas demand in the region.
Meanwhile, gas will also outperform oil in terms of production growth. Between 2012 and 2017, we expect
gas production to grow steadily at an average rate of 6.2% per annum, mainly as a result of production gains
in Australia, China and Papua New Guinea (PNG). Meanwhile, oil production is projected to grow at a
slower average rate of about 1.3% per annum over the same five-year period. However, we do expect gains
in gas output to slow after 2017, particularly as the high cost of gas development in Australia puts the
brakes on massive gas projects in the region.
Page 92
However, the expansion in LNG production is likely to slow after current developments in Australia are
completed. With the future of LNG prices in flux, producers are not likely to invest in yet more large LNG
projects when returns are uncertain, especially given high development costs in Australia. Moreover,
traditional producers such as Malaysia and Indonesia may see production increases, but the beginning of
LNG imports into these countries will certainly limit the extent to which net LNG exports would rise.
Growing caution with regards to LNG developments in Australia could, however, offer new opportunities
for other countries in the region:
Page 93
Papua New Guinea: Total's farm-in to InterOil's Elk-Antelope fields, which could contain sufficient
resources to justify a LNG export project, is yet another endorsement of the country's rich potential.
ExxonMobil had previously expressed more certainty in moving ahead with its PNG LNG project than
its proposed Scarborough project in Western Australia. Like Australia, PNG is located close to LNG
consumers in Asia while its small population positions it well to export gas extracted from its fields. The
nascent gas producer is likely to face less stringent regulatory requirements from the government, which
is eager to tap hydrocarbons revenues to support the country.
New Zealand: The country is actively seeking foreign investment to build up its hydrocarbons sector.
Like PNG, its small population would also enable producers to export much of the gas developed to the
more lucrative export market. New Zealand could be a longer-term play compared to PNG, however, as
exploration is still in its early stages.
Producers that are still hoping to tap Australia's rich gas potential for LNG exports will most likely
increasingly look to floating LNG (FLNG) production solutions. Since Shell took the lead with its Prelude
project, at least four other proposed developments have leaned towards a floating concept - GDF Suez's
Bonaparte, PTTEP's Cash-Maple, ExxonMobil's Scarborough and Woodside's Browse project. Malaysia
has also adopted FLNG as a solution when commoditising gas from stranded fields, with two FLNG
projects scheduled to come online from 2016. The Abadi LNG project in Indonesia has also taken up a
floating solution. These projects are of a smaller scale, but the flexibility in constructing facilities will allow
firms to overcome local cost constraints to bring fields into production as early as possible.
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*Positive trade = net exporter; Negative trade = net importer; e/f = estimate/forecast. Source: EIA, BMI
Page 95
*Countries include Japan, China, South Korea, Taiwan, India, Thailand, Singapore, Pakistan, Vietnam and Philippines. Countries
include PNG, Indonesia, Malaysia and Australia. Source: EIA, BMI
This reliance on LNG has also made the region a central player in the current debate over LNG pricing, as it
grows increasingly restless at having to pay a premium for LNG relative to other major LNG markets in the
world.
Page 96
Japan, in particular, has taken the lead in spearheading efforts to revise the LNG pricing mechanism.
Perceiving oil-linked prices as inaccurate depictions of the global gas market, Japan has actively pushed for
the development of a spot market to price LNG deliveries. In September 2013, it announced that it would
publish the average price that its importers pay for LNG, and use this price to set the level at which LNG
futures contracts in the Tokyo Commodity Exchange will trade from 2015.
Other measures include talks of joint tenders for LNG supplies between Japan and India, which could
increase the collective bargaining power of buyers vis-a-vis sellers. Another trend we expect to see is a
pick-up in orders of LNG carriers, as Asian importers seek to address delivery bottlenecks and costs by
increasing the number of vessels available to transport LNG.
However, despite continued efforts by the region's major LNG importers to lead the global debate on LNG
pricing, we believe this will have only a limited effect with regards to lowering prices - due to tightness in
the physical LNG market. This tightness is only expected to be relieved with greater liberalisation of the US
Page 97
LNG export market from 2018 - where the brownfield nature of LNG projects and low domestic gas prices
make the country's producers the most willing and able in the world to sell LNG at lower prices.
Therefore, it is our view that LNG prices in Asia will not fall below US$10 per mn British Thermal Units
(mn BTU) over our ten-year forecast period. However, a faster-than-expected increase in global LNG
supplies could push prices down and boost Asian LNG consumption beyond our current forecast levels.
NB: Additional fixed price includes the estimated cost of LNG production and shipping. US Henry Hub price is based on BMI's
forecast of US Henry Hub. e/f=estimate/forecast. Source: Bloomberg, BMI.
Page 98
Source: EIA
The EIA's updated study of the world's shale resource estimates also includes provisional figures for shale
oil. These new estimates suggest that shale oil could add significant upside to China and India's proven oil
reserves and long-term production potential, though this will most likely be realised only towards the tailend of our forecast period for China and beyond our 10-year timeframe for India.
Page 99
Source: EIA
This potential has seen a step-up in exploration efforts in China and Australia, and Indonesia has also begun
to open up to shale gas investment. Vietnam and Pakistan have also received unconventional attention from
Italian major Eni, though activities in India are being held back by a pending draft law on shale gas.
China has been most active in attracting investment into its shale potential in the region. It has officially
targeted annual shale gas production of 6.5bcm by 2015 and a further 60bcm to 100bcm by 2020 - targets
that the country may miss given the need to dramatically ramp-up production. To incentivise shale gas
developments, China has introduced subsidies and has opened up entry requirements into the country's shale
plays.
However, its complicated geology has seen companies like Shell experience difficulties translating its
potential into commercial development. Moreover, the award of shale gas blocks to non-traditional players
in its 2nd Shale Gas Round could also have slowed the rate of exploration, as the Ministry of Land and
Resources (MLR) found that some of the 16 companies awarded exploration rights to the 19 blocks offered
had barely started exploration and development works. Sinopec's recent declaration of commerciality at its
Page 100
Fuling block has brought some cheer to an otherwise disappointing drilling campaign in 2013, and results
from further exploration in 2014 would give a clearer indication of the level of maturity in China's nascent
flirtation with its shale gas potential.
In general, geological challenges, water scarcity, infrastructure issues, state-regulated prices and
environmental concerns could prevent a shale revolution from sweeping through Asia in the short term, but
in the longer term momentum will continue to build. Crucially, the technology is available, and it is
constantly evolving. In time, geological understanding of shale formations and their properties in Asia are
likely to improve. Research into more efficient use of resources - water among others - in fracking could
also reduce the environmental risks of operations. The long-term demand for gas is undeniable and political
pressure could swing in favour of tapping into domestic shale resources in order to reduce energy costs.
What will differentiate the Asian shale revolution from the one in the US will be its leading actors. In the
US, it was a bottom-up effort - technology developed by the private sector was tested and deployed on
private land, spurred on by high natural gas prices determined by market forces. In Asia, with the exception
of Australia, the effort is likely to be top-down and state-led, carried out through private collaboration with
national oil companies (NOCs).
Refining Woes
Asia has the largest refining capacity globally, and we estimate that it accounted for 33% of global refining
capacity in 2013. Singapore, Japan and South Korea are the region's refining giants, while China and India
Page 101
continue to expand their capacities to meet growing domestic demand. At least one 300,000b/d project will
be brought online in Vietnam (with another 600,000b/d refinery proposed), while Indonesia is also looking
to expand its downstream crude processing capacity by 900,000b/d.
Fuels Giant
Asia's Share Of Global Refining Capacity, 2012 & 2022
Despite countries such as Indonesia and Vietnam facing a shortfall in domestic refining capacity relative to
their consumption needs, we highlight the risk of overcapacity in the region's downstream segment. Indeed,
Asian production has to compete with other products in the global market, particularly as the Middle
Eastern countries bring their large mega-refinery projects online in the next decade.
Moreover, refining margins in the region could be weak, in view of high crude feedstock prices and strong
competition in the open refined products market. This is further complicated by state-regulated pricing in
many developing countries, limiting the extent to which producers can pass costs on to consumers.
Page 102
30,000
20,000
2022f
2021f
2020f
2019f
2018f
2017f
2016f
2015f
2014f
2012
2011
2010
2013e
10,000
The region's traditional refiners, particularly those with smaller plants and high crude import dependency,
are also losing out market share as a result of growing self-sufficiency in large markets such as China and
India, even as they struggle with emergent producers in the Middle East for a slice of the remaining market.
The Asian market is also being targeted by European exports, as the US downstream renaissance has pushed
Europe's battered refiners out of their traditional markets. Australia has been hit particularly hard, with
Shell's Geelong refinery set to be the next victim of closure. Japanese refiners Cosmo and Idemitsu have
also been rationalising their operations by shuttering production capacity.
These trends mean that profits in the downstream segment will come under price pressures across the
region. It could prompt private players to continue divesting downstream assets in smaller demand markets
such as Malaysia and Philippines. The possible exit of smaller refineries opens up room for existing players
to dive into newly available markets, although these players (for example, Singapore's large refineries) will
have to ensure that their plants are sufficiently equipped and modernised to withstand competition from
emerging players such as China. NOCs are also likely to pick up the slack in highly regulated markets, to
reduce fuel import dependency. There have been plans for many of the region's NOCs to establish joint
Page 103
ventures (JVs) with foreign partners to fund large refinery projects deemed to be more profitable (see
'Downstream Expansion Looms In South East Asia', January 21 2013). Whether or not these will fall
through will depend on the incentives that governments are willing to offer foreign partners.
Page 104
Saudi Arabia's signal that it would step back from its traditional swing producer role highlights OPEC's
response to shifting fundamentals in the global market. Reports are emerging that Saudi Arabia has
signalled that any necessary curtailment of production by OPEC would have to come in a coordinated
move. Traditionally, while in principle the cartel has to move in coordination and cooperation to alter
supplies on the global oil markets, it has been primarily Saudi Arabia that has fluctuated its output. Given
the tensions in play, the coordinated action Riyadh is seeking will be difficult to organise but may well be
necessary. However, we note that Saudi Arabia's resolve not to go it alone would certainly be tested if
prices dropped to below US$80/bbl.
Supporting this shift in strategy, there may well be growing recognition in Riyadh that given the scale of the
potential changes underway, acting independently may not be in its best interests of OPEC itself. In our
view, the key challenges that OPEC must manage are:
Rising OPEC Production: Namely from Iraq, which is still outside the production quota system, but is on
track for robust expansion of its output. This is already leading to tensions among other producers as they
increasingly compete for market share in Asia. Other producers such as the UAE are also investing
billions in raising upstream capacity.
Page 105
Potential Return Of Iran: As we have noted previously, the removal of sanctions on Iran's oil sector
would be a game changer and over time could see Iran return to pre-sanctions production levels
approaching 4mn barrels per day (b/d). With Iran claiming to have secured an agreement at the most
recent OPEC summit that would see other members 'make room' for a return of its crude should
restrictions be loosened, the impact on the state of the global market could be dramatic.
Source: Bloomberg
The latest developments pose downside risks to our production forecasts for OPEC members, but could also
put pressure on prices over the longer term should countries forgo planned upstream investment.
Iraq, South Sudan, Libya and Kazakhstan are the main oil producers that presented a production challenge
for 2013. Timely recovery in their volumes is uncertain.
The Kashagan field in Kazakhstan, the largest greenfield project in the world, came online for only a
matter of a few weeks before being shut down due to technical problems, therefore further risking further
delays to its commercial production in 2014.
Most of Libya's oil remains shut-in since August, with anti-government fractions including militias, clans
and public workers blockading oilfields and export infrastructure. Blockaded oil ports in Eastern Libya
Page 106
failed to re-open after a deadline set by the central government in Tripoli passed in mid-December and
they remain closed at time of writing.
The escalation of in-fighting between the military and rebel forces in South Sudan seems to have halted
the majority of the country's production, with fighting taking place in the Unity and Upper Nile States,
where the majority of oil is produced. Peace talks are ongoing though we see scope for violence to
escalate further, with signs that the situation could unravel into a prolonged war of attrition between the
two sides - posing a serious risk to the country's oil production.
Continued challenges in Iraq's upstream environment put the country's plans for a big increase in oil
production growth into further doubt. While the start of major upstream projects over in the coming
quarters highlights Iraq's potential, volatile production and weak gas production underscore the
country's challenges. Although we expect strong growth in both oil and gas output over the course of our
forecast period to 2022, we expect delays and setbacks to continue, causing production to underperform
the country's raw potential. As a result, we have taken a more bearish production outlook of just under
3.4mn b/d for 2014 compared to an average of 3.5mn b/d previously. Most recently, the security
environment has deteriorated since sectarian tension flared up in Anbar province, raising another red flag
with regards to Iraq's operating landscape.
Elsewhere, production gains in Africa, North America and Latin America will drive overall global
production growth for 2014. We forecast global crude oil production to be 88.6mn b/d in 2014, up 2% yearon-year. US crude oil production will reach 11.5mn b/d in 2014, up nearly 5% y-o-y (though lower than the
EIA's forecast for 12.1mn b/d). We are also closely watching the Mexico energy reforms, which could also
unleash a new wave of investment in the coming years.
Page 107
Demand will be more buoyant than in 2013. Consumption of refined fuels (our measure of oil demand)
across major emerging market is going to increase at a healthy pace, offsetting muted growth from Western
Europe and North America, both of which are seeing a structural decline as energy efficiency rises (in the
case of Western Europe it is compounded by a cyclical decline as a result of years of weak economic
growth).
Global oil consumption for 2014 will reach 88.14mn b/d up 1.7% y-o-y, of which the US will account for
17.8mn b/d, China for 11mn b/d, Japan for 4.5mn b/d, India for 3.92mn b/d and Russia for 3.3mn b/
d. BMI's global macroeconomic assumptions underpin our consumption forecast. Accordingly, BMI's
global economists forecast 3.2% real growth for 2014, up from 2.6% in 2013. Our outlook on Chinese GDP
growth is more benign than it was at this time last year, which is also reflected in our forecasts for oil
consumption growth of 4% y-o-y for the country.
Page 108
Our global oil supply and demand balance shows a surplus of 489,000 b/d for 2014, which aligns with our
expectations for lower average Brent prices over the year.
Production outages and below-expectation output have worked to sustain Brent prices at historic highs,
creating a conducive pricing environment for capex. In addition, the bounty in the United States shale
formations has attracted the industry, with several players earmarking a large proportion of their budgets for
US shale (liquids) exploration.
Page 109
Since 2010, when the industry recovered from the downturn of 2009, capex has been increasing at an
average of 12% y-o-y, according to data compiled by Bloomberg. However, following four years of rapid
increases in capital spending by international oil companies (IOCs) and national oil companies (NOCs), the
mood seems to be turning. Indeed, development costs have increased in tandem with spending in recent
years, as projects become more complex and skills shortages stretch the industry. According to data from
Bloomberg, exploration costs rose by an average of 20% y-o-y in 2012 and 2011, and considering the
similar growth trajectory in spending over 2013, we would expect a similar cost rise last year too.
A typical 5-year cycle in project development from exploration and appraisal (E&A) to commercial
production means that a lot of investors are now expecting companies to begin consolidating the gains from
the investment that started around 2010. We have therefore seen the industry discourse focus increasingly
on investor returns and dividends. A case in point is French company Total, which announced a reduction
Page 110
in capex is in store post-2015 and that it will focus on cash flow from new developments that are due to
come online.
There are divergent expectations in the market for 2014 E&P capex. Our review of the announced 2014
capex plans from IOCs and NOCs shows that the majority of companies are looking at lower capital
spending in 2014 compared to 2013 (see table below). In a study on global E&P capex, Barclays estimates
that 2013 capex (organic) reached US$680bn and that the figure will increase in 2014 by 6% to US$723bn.
The largest oil field services companies also have given estimates that they expect capex in global E&P to
rise between 8%-10% in 2014.
2013 Capex
2014 Capex
Total
28
26
Gazprom
32
21.1
Statoil
19
na
BP
na
25
ConocoPhillips
16
16.7
Chevron
42
39.8
Exxon
38
na
GazpromNeft
8.2
8.5
PTT (Thailand)
12
10
Pertamina
na
7.9
A survey of analysts by Bloomberg, however, reveals that the industry is expecting capex growth to
decelerate in the coming years. For 2014, the global capex consensus forecast is US$541bn (-0.5% y-o-y),
rising to US$549bn (1.5% y-o-y) in 2015. Though the aggregate number is lower than the one quoted by the
Barclay's analysis (Bloomberg data excludes unlisted NOCs) the trend clearly indicates an expectation that
there will be a moderation in spending growth. This divergence in the outlook regarding capex plans is, in
our view, a reflection of the uncertainty regarding demand trends as well as the future pricing environment.
Page 111
Fuelling the uncertainty in 2014 is the barrage of elections in major oil producing and consuming markets in
2014 - including Brazil, Iraq, Colombia, Indonesia, India and Turkey. Energy policy is always a topic on the
agenda, whether it is the upstream or the fuels market prices (and subsidies) that feature in the debate.
BMI's global political risk analysts do not expect much turmoil to stem from these, though for the energy
markets, changes in energy policy could mean changes to the operating environment. Brazil, Indonesia,
India and Iraq are the ones we will be watching closely as they are the most likely to have an impact on our
2014 global oil market outlook.
Page 112
Appendix
Asia - Regional Appendix
The data contained in these appendix tables is correct as of 1 January 2014. It represents a snapshot of our
regional forecasts at the end of our last publishing quarter. It is included for reference purposes only. Latest
data, reflecting forecasts made for the market this quarter, can be found in the Industry Forecast Scenario
section of this report. Please note, that because this table represents a snapshot of our last regional forecasts,
whereas data included in the Industry Forecast Scenario represents our latest forecasts made this quarter,
country-specific data may not match.
2011
2012
2013
2014
2015
2016
2017
2018
Australia
1,105
1,126
1,136
1,146
1,157
1,167
1,178
1,188
China
9,810
10,277
10,688
11,115
11,449
11,792
12,146
12,510
365
290
325
353
377
398
418
437
India
3,411
3,622
3,754
3,920
4,124
4,358
4,616
4,892
Indonesia
1,384
1,384
1,370
1,356
1,363
1,374
1,385
1,399
Japan
4,608
4,910
4,699
4,534
4,479
4,461
4,452
4,451
Malaysia
598
598
616
636
657
680
703
728
Pakistan
418
440
462
481
495
505
510
531
20
20
20
20
20
21
21
21
Philippines
316
302
317
330
337
340
343
348
Singapore
1,250
1,380
1,397
1,431
1,467
1,508
1,552
1,598
South Korea
2,258
2,301
2,313
2,325
2,334
2,348
2,360
2,367
Taiwan
1,030
1,080
1,094
1,119
1,147
1,181
1,217
1,247
Thailand
1,020
1,009
1,036
1,062
1,087
1,112
1,137
1,160
Vietnam
352
376
389
401
415
429
444
460
27,944
29,115
29,616
30,228
30,908
31,676
32,483
33,339
963
994
1,024
1,054
1,085
1,115
1,141
1,169
28,907
30,109
30,641
31,283
31,992
32,790
33,624
34,507
Hong Kong
BMI Universe
Other Asia
Regional Total
Page 113
2015
2016
2017
2018
2019
2020
2021
2022
1,157
1,167
1,178
1,188
1,199
1,210
1,221
1,232
11,449
11,792
12,146
12,510
12,823
13,144
13,472
13,809
377
398
418
437
456
475
494
513
India
4,124
4,358
4,616
4,892
5,186
5,495
5,828
6,187
Indonesia
1,363
1,374
1,385
1,399
1,413
1,427
1,449
1,470
Japan
4,479
4,461
4,452
4,451
4,415
4,371
4,323
4,280
Malaysia
657
680
703
728
753
780
806
833
Pakistan
495
505
510
531
553
576
600
625
20
21
21
21
22
22
23
23
Philippines
337
340
343
348
354
361
368
376
Singapore
1,467
1,508
1,552
1,598
1,646
1,698
1,752
1,809
South Korea
2,334
2,348
2,360
2,367
2,374
2,381
2,388
2,396
Taiwan
1,147
1,181
1,217
1,247
1,275
1,303
1,331
1,371
Thailand
1,087
1,112
1,137
1,160
1,184
1,219
1,256
1,293
Vietnam
415
429
444
460
474
488
503
518
30,908
31,676
32,483
33,339
34,126
34,949
35,814
36,737
1,085
1,115
1,141
1,169
1,194
1,221
1,257
1,258
31,992
32,790
33,624
34,507
35,321
36,170
37,071
37,995
Australia
China
Hong Kong
BMI Universe
Other Asia
Regional Total
2011
2012
2013
2014
2015
2016
2017
2018
496
484
491
485
480
478
477
476
4,106
4,175
4,299
4,384
4,405
4,445
4,445
4,423
904
899
923
951
977
963
949
936
1,003
962
920
926
932
907
885
868
19
18
17
17
17
16
16
16
Malaysia
605
622
687
708
746
828
846
912
Pakistan
63
62
63
65
66
68
68
70
30
27
29
35
42
47
47
46
Australia
China
Hong Kong
India
Indonesia
Japan
Page 114
2011
2012
2013
2014
2015
2016
2017
2018
Philippines
30
23
20
29
33
33
34
34
Singapore
20
21
21
21
20
20
19
19
Thailand
397
414
413
418
433
427
419
408
Vietnam
319
359
377
402
417
426
423
418
7995
8068
8262
8,442
8,571
8,661
8,631
8,629
336
337
344
341
338
331
322
314
8330
8405
8606
8783
8909
8991
8953
8943
South Korea
Taiwan
BMI Universe
Other Asia
Regional Total
2015
2016
2017
2018
2019
2020
2021
2022
480
478
477
476
475
474
476
477
4,405
4,445
4,445
4,423
4,401
4,383
4,349
4,314
India
977
963
949
936
923
911
899
887
Indonesia
932
907
885
868
853
838
823
808
17
16
16
16
16
15
15
15
Malaysia
746
828
846
912
969
941
914
887
Pakistan
66
68
68
70
71
72
73
75
42
47
47
46
44
42
40
38
Philippines
33
33
34
34
33
32
31
31
Singapore
20
20
19
19
19
18
18
18
Thailand
433
427
419
408
398
389
379
370
Vietnam
417
426
423
418
407
397
385
374
8,571
8,661
8,631
8,629
8,612
8,516
8,404
8,296
338
331
322
314
306
298
292
292
Australia
China
Hong Kong
Japan
South Korea
Taiwan
BMI Universe
Other Asia
Page 115
Regional Total
2015
2016
2017
2018
2019
2020
2021
2022
8909
8991
8953
8943
8918
8814
8696
8588
2011
2012
2013
2014
2015
2016
2017
2018
757
738
668
605
543
543
543
543
10,185
10,385
10,826
11,086
11,434
11,634
11,919
11,919
India
4,000
4,321
4,622
4,742
4,872
4,872
5,138
5,138
Indonesia
1,056
1,056
1,056
1,119
1,119
1,119
1,119
1,119
Japan
4,730
4,479
4,475
4,073
4,073
4,073
4,073
4,073
Malaysia
539
539
588
588
588
588
588
588
Pakistan
286
286
286
400
400
650
650
650
37
37
37
37
37
37
37
37
Philippines
273
273
273
273
273
273
273
273
Singapore
1,357
1,357
1,357
1,357
1,357
1,357
1,357
1,357
South Korea
2,722
2,760
2,755
2,801
2,801
2,801
2,801
2,801
Taiwan
1,310
1,310
1,310
1,310
1,090
1,090
1,090
1,090
Thailand
1,214
1,214
1,214
1,214
1,214
1,524
1,524
1,524
Vietnam
140
140
140
140
140
190
345
451
28,605
28,893
29,605
29,744
29,940
30,750
31,456
31,562
333
338
341
357
366
374
378
380
28,937
29,231
29,946
30,101
30,307
31,125
31,835
31,942
Australia
China
Hong Kong
BMI Universe
Other Asia
Regional Total
Australia
China
2015
2016
2017
2018
2019
2020
2021.
2022
543
543
543
543
543
543
543
543
11,434
11,634
11,919
11,919
11,919
11,919
11,919
11,919
Page 116
2015
2016
2017
2018
2019
2020
2021.
2022
India
4,872
4,872
5,138
5,138
5,138
5,138
5,138
5,138
Indonesia
1,119
1,119
1,119
1,119
1,119
1,119
1,119
1,119
Japan
4,073
4,073
4,073
4,073
4,073
4,073
4,073
4,073
Malaysia
588
588
588
588
738
888
888
888
Pakistan
400
650
650
650
650
650
650
650
37
37
37
37
37
37
37
37
Philippines
273
273
273
273
273
273
273
273
Singapore
1,357
1,357
1,357
1,357
1,357
1,357
1,357
1,357
South Korea
2,801
2,801
2,801
2,801
2,801
2,801
2,801
2,801
Taiwan
1,090
1,090
1,090
1,090
1,090
1,090
1,090
1,090
Thailand
1,214
1,524
1,524
1,524
1,524
1,524
1,524
1,524
Vietnam
140
190
345
451
501
501
501
501
29,940
30,750
31,456
31,562
31,762
31,912
31,912
31,912
366
374
378
380
383
385
385
386
30,307
31,125
31,835
31,942
32,145
32,297
32,297
32,298
Hong Kong
BMI Universe
Other Asia
Regional Total
2011
2012
2013
2014
2015
2016
2017
2018
45.58
48.24
49.78
64.11
103.18
118.91
123.77
134.29
102.77
108.40
112.74
117.25
123.11
129.26
135.73
142.51
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
India
47.62
40.38
39.17
38.76
37.61
38.24
46.70
58.39
Indonesia
76.25
71.25
72.30
75.99
76.83
76.53
77.03
75.49
4.99
3.27
3.20
3.12
3.05
2.98
2.91
2.85
Malaysia
61.73
62.35
68.27
71.68
75.99
80.16
80.97
81.98
Pakistan
39.15
38.76
39.34
39.73
40.13
39.73
39.33
38.55
0.10
0.10
0.10
5.04
9.83
9.83
12.04
14.81
Philippines
2.90
3.79
3.77
3.96
4.08
4.12
4.14
4.14
Singapore
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
South Korea
1.01
0.44
0.42
0.41
0.40
0.39
0.38
0.36
Australia
China
Hong Kong
Japan
Page 117
2011
2012
2013
2014
2015
2016
2017
2018
0.29
0.28
0.27
0.26
0.25
0.25
0.24
0.23
Thailand
36.99
36.62
36.62
36.99
37.59
38.19
38.79
39.38
Vietnam
7.71
9.30
12.04
12.25
13.08
13.44
13.04
14.06
427.09
423.18
438.03
469.56
525.14
552.03
575.07
607.04
70.07
73.92
77.67
81.60
85.58
89.78
93.87
98.15
497
497
516
551
611
642
669
705
Taiwan
BMI Universe
Other Asia
Regional Total
2015
2016
2017
2018
2019
2020
2021
2022
Australia
103.18
118.91
123.77
134.29
143.63
147.04
147.73
148
China
123.11
129.26
135.73
142.51
152.49
165.45
179.52
195
0.00
0.00
0.00
0.00
0.00
0.00
0.00
India
37.61
38.24
46.70
58.39
62.38
60.54
58.76
57
Indonesia
76.83
76.53
77.03
75.49
76.63
77.80
76.24
77
3.05
2.98
2.91
2.85
2.78
2.72
2.65
Malaysia
75.99
80.16
80.97
81.98
83.62
80.69
78.27
76
Pakistan
40.13
39.73
39.33
38.55
38.16
37.40
37.02
37
9.83
9.83
12.04
14.81
15.36
17.85
20.35
20
Philippines
4.08
4.12
4.14
4.14
4.14
4.14
4.14
Singapore
0.00
0.00
0.00
0.00
0.00
0.00
0.00
South Korea
0.40
0.39
0.38
0.36
0.35
0.34
0.33
Taiwan
0.25
0.25
0.24
0.23
0.22
0.22
0.21
Thailand
37.59
38.19
38.79
39.38
39.96
39.56
39.16
39
Vietnam
13.08
13.44
13.04
14.06
15.85
16.40
16.25
16
525.14
552.03
575.07
607.04
635.58
650.16
660.64
672.11
85.58
89.78
93.87
98.15
103.53
108.60
113.88
114.88
611
642
669
705
739
759
775
787
Hong Kong
Japan
BMI Universe
Other Asia
Regional Total
Page 118
2011
2012
2013
2014
2015
2016
2017
2018
35.09
28.89
29.61
30.35
31.11
31.89
32.53
33.18
130.92
145.89
161.51
176.04
191.88
207.23
221.74
237.26
3.20
3.50
3.70
3.86
4.02
4.18
4.35
4.52
India
64.01
58.77
59.01
62.42
66.40
70.80
75.54
80.57
Indonesia
37.58
39.08
40.65
42.68
44.39
46.16
48.01
49.45
111.79
122.02
120.43
120.07
120.19
122.66
124.86
124.99
Malaysia
30.62
31.23
32.48
33.78
34.79
35.84
36.73
37.65
Pakistan
39.15
38.76
39.34
39.73
40.53
41.34
42.17
43.01
0.10
0.10
0.10
0.11
0.11
0.11
0.11
0.11
Philippines
2.90
3.64
3.75
3.99
4.21
4.27
5.13
5.65
Singapore
8.78
8.94
9.17
9.49
9.81
10.16
10.51
10.86
South Korea
45.71
49.63
53.90
55.73
57.51
56.19
54.50
52.49
Taiwan
16.21
17.00
17.34
17.69
17.87
18.05
18.41
18.78
Thailand
46.57
49.26
51.72
54.05
56.48
59.02
61.68
64.46
Vietnam
7.71
9.30
12.04
12.25
13.77
14.44
14.42
16.56
580.34
606.03
634.75
662.25
693.08
722.34
750.69
779.53
70.07
73.92
77.67
81.60
85.58
89.78
93.87
98.15
650
680
712
744
779
812
845
878
Australia
China
Hong Kong
Japan
BMI Universe
Other Asia
Regional Total
2015
2016
2017
2018
2019
2020
2021
2022
31.11
31.89
32.53
33.18
33.84
34.52
35.21
36
191.88
207.23
221.74
237.26
253.87
271.64
290.66
311
4.02
4.18
4.35
4.52
4.69
4.87
5.06
India
66.40
70.80
75.54
80.57
85.85
91.36
97.24
104
Indonesia
44.39
46.16
48.01
49.45
50.93
52.46
54.03
56
120.19
122.66
124.86
124.99
124.74
124.74
123.49
122
Malaysia
34.79
35.84
36.73
37.65
38.59
38.98
39.37
40
Pakistan
40.53
41.34
42.17
43.01
43.87
44.75
45.64
47
0.11
0.11
0.11
0.11
0.12
0.12
0.12
Philippines
4.21
4.27
5.13
5.65
6.28
6.40
6.85
Australia
China
Hong Kong
Japan
Page 119
2015
2016
2017
2018
2019
2020
2021
2022
9.81
10.16
10.51
10.86
11.23
11.62
12.02
12
South Korea
57.51
56.19
54.50
52.49
50.39
49.38
50.57
52
Taiwan
17.87
18.05
18.41
18.78
19.34
19.92
20.72
22
Thailand
56.48
59.02
61.68
64.46
67.36
70.39
73.56
77
Vietnam
13.77
14.44
14.42
16.56
18.85
20.58
21.52
21
693.08
722.34
750.69
779.53
809.95
841.72
876.05
911.30
85.58
89.78
93.87
98.15
103.53
108.60
113.88
114.88
779
812
845
878
913
950
990
1,026
Singapore
BMI Universe
Other Asia
Regional Total
2011
2012
2013
2014
2015
2016
2017
2018
10.49
19.35
20.16
33.75
72.07
87.02
91.24
101.11
(16.90)
(20.27)
(23.50)
(26.80)
(33.79)
(35.86)
(40.00)
(42.40)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
(16.39)
(18.39)
(19.84)
(23.67)
(28.79)
(32.57)
(28.86)
(22.18)
29.10
28.43
21.60
26.16
25.30
23.21
21.87
18.89
(106.80)
(118.75)
(117.24)
(116.95)
(117.14)
(119.67)
(121.95)
(122.14)
Malaysia
0.00
29.00
33.67
35.78
39.07
42.21
42.11
43.27
Pakistan
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
4.93
9.72
9.72
11.93
14.70
Philippines
0.00
0.00
0.00
(0.03)
(0.13)
(0.13)
(1.05)
(1.51)
Singapore
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
(44.70)
(49.19)
(53.47)
(55.32)
(57.11)
(55.80)
(54.13)
(52.12)
Taiwan
0.00
(16.72)
(17.07)
(17.43)
(17.61)
(17.80)
(18.17)
(18.54)
Thailand
0.00
0.00
(2.15)
(3.00)
(5.00)
(7.00)
(9.00)
(11.00)
Vietnam
0.00
0.00
0.00
0.00
(0.69)
(1.00)
(1.38)
(2.50)
(145.20)
(146.55)
(157.83)
(142.57)
(114.11)
(107.68)
(107.37)
(94.44)
(8.40)
(20.71)
(24.62)
(35.71)
(44.27)
(51.61)
(62.95)
(78.80)
(153.60)
(167.26)
(182.45)
(178.29)
(158.38)
(159.29)
(170.32)
(173.23)
Australia
China
Hong Kong
India
Indonesia
Japan
South Korea
BMI Universe
Other Asia
Regional Total
Page 120
2015
2016
2017
2018
2019
2020
2021
2022
72.07
87.02
91.24
101.11
109.79
112.52
112.52
112.52
(33.79)
(35.86)
(40.00)
(42.40)
(44.00)
(46.34)
(48.83)
(49.65)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
(28.79)
(32.57)
(28.86)
(22.18)
(23.48)
(30.82)
(38.49)
(46.52)
25.30
23.21
21.87
18.89
18.55
18.19
15.06
13.85
(117.14)
(119.67)
(121.95)
(122.14)
(121.96)
(122.02)
(120.84)
(119.66)
Malaysia
39.07
42.21
42.11
43.27
43.96
40.65
37.84
35.49
Pakistan
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
9.72
9.72
11.93
14.70
15.25
17.74
20.23
20.22
Philippines
(0.13)
(0.13)
(1.05)
(1.51)
(2.13)
(2.26)
(2.70)
(2.87)
Singapore
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
South Korea
(57.11)
(55.80)
(54.13)
(52.12)
(50.03)
(49.04)
(50.23)
(51.66)
Taiwan
(17.61)
(17.80)
(18.17)
(18.54)
(19.11)
(19.70)
(20.50)
(21.34)
Thailand
(5.00)
(7.00)
(9.00)
(11.00)
(13.00)
(16.00)
(20.00)
(24.00)
Vietnam
(0.69)
(1.00)
(1.38)
(2.50)
(3.00)
(4.18)
(5.27)
(5.52)
(114.11)
(107.68)
(107.37)
(94.44)
(89.17)
(101.27)
(121.21)
(139.15)
(44.27)
(51.61)
(62.95)
(78.80)
(93.90)
(108.61)
(136.65)
(135.65)
(158.38)
(159.29)
(170.32)
(173.23)
(183.06)
(209.89)
(257.86)
(274.80)
Australia
China
Hong Kong
India
Indonesia
Japan
BMI Universe
Other Asia
Regional Total
Page 121
The Liquefied Petroleum Gas (LPG) component is either wholly accounted for in the refined products
breakdown tables, or, if the country is a LPG producer at the wellhead then it is contained at the end in its
own separate table that includes refined and wellhead production.
2012
Motor Gasoline Production, 000b/d
2013e 2014f
2015f
2016f
2017f
56.3
56.6
56.9
57.0
74.1
111.2
0.5
0.5
0.5
0.2
30.0
50.0
2.5
2.4
2.4
2.4
3.0
4.5
42.6
42.6
42.6
42.6
42.6
42.6
0.9
0.9
0.9
0.9
1.2
1.7
0.5
0.5
0.5
0.2
30.0
50.0
0.0
0.0
0.0
0.0
0.0
0.1
0.7
0.7
0.7
0.7
0.7
0.7
0.9
0.9
0.9
0.9
1.2
1.7
0.5
0.5
0.5
0.2
30.0
50.0
0.0
0.0
0.0
0.0
0.0
0.1
0.7
0.7
0.7
0.7
0.7
0.7
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
56.5
56.8
57.1
57.2
74.4
111.5
0.5
0.5
0.5
0.2
30.0
50.0
2.6
2.6
2.5
2.5
3.1
4.6
42.8
42.8
42.8
42.8
42.8
42.8
4.5
4.5
4.5
4.5
5.9
8.8
0.5
0.5
0.5
0.2
30.0
50.0
0.2
0.2
0.2
0.2
0.2
0.3
3.4
3.4
3.4
3.4
3.4
3.4
10.7
10.8
10.8
10.9
14.1
21.2
0.5
0.5
0.5
0.2
30.0
50.0
Page 122
2012
2013e 2014f
2015f
2016f
2017f
0.4
0.4
0.4
0.4
0.5
0.7
8.1
8.1
8.1
8.1
8.1
8.1
3.2
3.2
3.2
3.2
4.2
6.3
0.5
0.5
0.5
0.2
30.0
50.0
0.1
0.1
0.1
0.1
0.2
0.3
2.4
2.4
2.4
2.4
2.4
2.4
2018f
Motor Gasoline Production, 000b/d
2019f
2020f
2021f
2022f
2023f
166.8
191.8
201.4
201.8
202.2
202.6
50.0
15.0
5.0
0.2
0.2
0.2
6.2
7.2
7.5
7.6
7.6
7.7
42.6
42.6
42.6
42.6
42.6
42.6
2.6
3.0
3.1
3.1
3.1
3.2
50.0
15.0
5.0
0.2
0.2
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.7
0.7
0.7
0.7
0.7
0.7
2.6
3.0
3.1
3.1
3.1
3.2
50.0
15.0
5.0
0.2
0.2
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.7
0.7
0.7
0.7
0.7
0.7
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
167.3
192.4
202.0
202.4
202.8
203.2
50.0
15.0
5.0
0.2
0.2
0.2
6.9
8.0
8.4
8.4
8.4
8.5
42.8
42.8
42.8
42.8
42.8
42.8
13.2
15.2
16.0
16.0
16.1
16.1
50.0
15.0
5.0
0.2
0.2
0.2
0.4
0.5
0.5
0.5
0.5
0.5
Page 123
2018f
Residual Fuel Oil Production, % of Domestic Production
2019f
2020f
2021f
2022f
2023f
3.4
3.4
3.4
3.4
3.4
3.4
31.8
36.6
38.4
38.5
38.5
38.6
50.0
15.0
5.0
0.2
0.2
0.2
1.1
1.2
1.3
1.3
1.3
1.3
8.1
8.1
8.1
8.1
8.1
8.1
9.5
10.9
11.4
11.5
11.5
11.5
50.0
15.0
5.0
0.2
0.2
0.2
0.4
0.4
0.4
0.4
0.4
0.4
2.4
2.4
2.4
2.4
2.4
2.4
2013e 2014f
2015f
2012
Motor Gasoline Consumption, 000b/d
2016f
2017f
118.0
122.1
125.8
130.2
134.7
139.4
6.8
3.5
3.0
3.5
3.5
3.5
31.4
31.4
31.4
31.4
31.4
31.4
5.3
5.2
5.3
5.4
5.5
5.6
23.1
24.0
24.7
25.5
26.4
27.4
6.8
3.5
3.0
3.5
3.5
3.5
6.2
6.2
6.2
6.2
6.2
6.2
1.0
1.0
1.1
1.1
1.1
1.1
21.0
21.7
22.3
23.1
23.9
24.8
6.8
3.5
3.0
3.5
3.5
3.5
5.6
5.6
5.6
5.6
5.6
5.6
1.0
1.0
1.0
1.0
1.0
1.0
2.2
2.3
2.3
2.4
2.5
2.6
6.8
3.5
3.0
3.5
3.5
3.5
0.6
0.6
0.6
0.6
0.6
0.6
0.1
0.1
0.1
0.1
0.1
0.1
127.0
131.5
135.4
140.2
145.1
150.2
6.8
3.5
3.0
3.5
3.5
3.5
33.8
33.8
33.8
33.8
33.8
33.8
Page 124
2012
Distillate Fuel Oil Consumption, US$bn
2013e 2014f
2015f
2016f
2017f
5.9
5.9
6.0
6.1
6.1
6.2
46.3
47.9
49.3
51.0
52.8
54.7
6.8
3.5
3.0
3.5
3.5
3.5
12.3
12.3
12.3
12.3
12.3
12.3
1.7
1.7
1.6
1.7
1.7
1.8
38.4
39.8
41.0
42.4
43.9
45.4
6.8
3.5
3.0
3.5
3.5
3.5
10.2
10.2
10.2
10.2
10.2
10.2
1.4
1.5
1.5
1.5
1.6
1.6
23.1
24.0
24.7
25.5
26.4
27.4
6.8
3.5
3.0
3.5
3.5
3.5
6.2
6.2
6.2
6.2
6.2
6.2
1.0
1.0
1.0
1.1
1.1
1.1
2018f
Motor Gasoline Consumption, 000b/d
2019f
2020f
2021f
2022f
2023f
144.3
148.6
153.1
157.7
162.4
167.3
3.5
3.0
3.0
3.0
3.0
3.0
31.4
31.4
31.4
31.4
31.4
31.4
5.4
5.6
5.7
5.9
6.1
6.3
28.3
29.2
30.0
30.9
31.9
32.8
3.5
3.0
3.0
3.0
3.0
3.0
6.2
6.2
6.2
6.2
6.2
6.2
1.1
1.1
1.1
1.2
1.2
1.3
25.6
26.4
27.2
28.0
28.9
29.7
3.5
3.0
3.0
3.0
3.0
3.0
5.6
5.6
5.6
5.6
5.6
5.6
1.0
1.0
1.0
1.1
1.1
1.1
2.7
2.8
2.8
2.9
3.0
3.1
3.5
3.0
3.0
3.0
3.0
3.0
0.6
0.6
0.6
0.6
0.6
0.6
Page 125
2018f
Kerosene Consumption, US$bn
2019f
2020f
2021f
2022f
2023f
0.1
0.1
0.1
0.1
0.1
0.1
155.4
160.1
164.9
169.8
174.9
180.2
3.5
3.0
3.0
3.0
3.0
3.0
33.8
33.8
33.8
33.8
33.8
33.8
6.4
6.6
6.8
7.0
7.2
7.5
56.6
58.3
60.0
61.8
63.7
65.6
3.5
3.0
3.0
3.0
3.0
3.0
12.3
12.3
12.3
12.3
12.3
12.3
1.8
1.9
2.0
2.0
2.1
2.2
47.0
48.4
49.9
51.4
52.9
54.5
3.5
3.0
3.0
3.0
3.0
3.0
10.2
10.2
10.2
10.2
10.2
10.2
1.6
1.6
1.7
1.7
1.8
1.9
28.3
29.2
30.0
30.9
31.9
32.8
3.5
3.0
3.0
3.0
3.0
3.0
6.2
6.2
6.2
6.2
6.2
6.2
1.1
1.1
1.1
1.2
1.2
1.2
2012
Total Net Exports of Motor Gasoline, 000b/d
2013e 2014f
2015f
2016f
2017f
-61.6
-65.5
-68.9
-73.1
-60.6
-28.2
13.3
6.2
5.2
6.2
-17.2
-53.4
-2.8
-2.8
-2.9
-3.1
-2.5
-1.1
-22.3
-23.1
-23.8
-24.7
-25.3
-25.6
7.1
3.6
3.1
3.6
2.5
1.4
-1.0
-1.0
-1.0
-1.0
-1.0
-1.0
-20.1
-20.8
-21.5
-22.2
-22.8
-23.0
7.1
3.6
3.1
3.6
2.4
1.1
-0.9
-0.9
-0.9
-0.9
-1.0
-0.9
-2.2
-2.3
-2.3
-2.4
-2.5
-2.6
6.8
3.5
3.0
3.5
3.5
3.5
Page 126
2012
Total Net Exports of Kerosene, US$bn
2013e 2014f
2015f
2016f
2017f
-0.1
-0.1
-0.1
-0.1
-0.1
-0.1
-70.5
-74.7
-78.4
-83.0
-70.7
-38.6
12.5
5.9
4.9
5.9
-14.8
-45.4
-3.3
-3.4
-3.4
-3.6
-3.0
-1.6
-41.8
-43.4
-44.8
-46.5
-46.9
-45.8
7.5
3.8
3.3
3.8
0.9
-2.3
-1.6
-1.5
-1.5
-1.6
-1.5
-1.5
-27.7
-29.0
-30.1
-31.5
-29.8
-24.2
9.5
4.7
3.9
4.7
-5.6
-18.6
-1.0
-1.1
-1.1
-1.1
-1.1
-0.8
-19.9
-20.7
-21.4
-22.3
-22.2
-21.0
7.9
4.0
3.4
4.0
-0.4
-5.3
-0.9
-0.9
-0.9
-0.9
-0.9
-0.8
2018f
Total Net Exports of Motor Gasoline, 000b/d
2019f
2020f
2021f
2022f
2023f
22.5
43.2
48.3
44.1
39.8
35.3
-179.5
92.1
11.9
-8.7
-9.8
-11.2
0.8
1.6
1.8
1.7
1.5
1.3
-25.7
-26.2
-26.9
-27.8
-28.7
-29.7
0.4
1.8
2.8
3.3
3.3
3.3
-1.0
-1.0
-1.0
-1.1
-1.1
-1.1
-23.0
-23.4
-24.1
-24.9
-25.7
-26.6
0.0
1.6
2.7
3.4
3.4
3.3
-0.9
-0.9
-0.9
-0.9
-1.0
-1.0
-2.7
-2.8
-2.8
-2.9
-3.0
-3.1
3.5
3.0
3.0
3.0
3.0
3.0
-0.1
-0.1
-0.1
-0.1
-0.1
-0.1
11.9
32.3
37.1
32.6
27.9
23.1
-130.7
172.0
14.9
-12.2
-14.4
-17.4
0.5
1.3
1.5
1.3
1.2
1.0
Page 127
2018f
Total Net Exports of Residual Fuel Oil, 000b/d
2019f
2020f
2021f
2022f
2023f
-43.3
-43.1
-44.0
-45.8
-47.6
-49.5
-5.5
-0.7
2.3
4.0
4.0
3.9
-1.4
-1.4
-1.4
-1.5
-1.6
-1.6
-15.2
-11.9
-11.5
-12.9
-14.4
-15.9
-37.2
-22.0
-3.2
12.3
11.3
10.5
-0.5
-0.4
-0.4
-0.4
-0.5
-0.5
-18.8
-18.3
-18.6
-19.5
-20.4
-21.3
-10.5
-3.0
1.8
4.7
4.6
4.6
-0.7
-0.7
-0.7
-0.7
-0.8
-0.8
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Glossary
Table: Glossary Of Terms
AOR
KCTS
APA
km
kilometres
API
LAB
bbl
barrel
LDPE
bcm
LNG
b/d
LPG
bn
billion
metres
boe
mcm
BTC
Baku-Tbilisi-Ceyhan Pipeline
Mcm
mn cubic metres
BTU
MEA
Capex
capital expenditure
mn
million
CBM
MoU
memorandum of understanding
CEE
mt
metric tonne
CPC
MW
megawatts
CSG
na
DoE
US Department of Energy
NGL
EBRD
NOC
EEZ
OECD
e/f
estimate/forecast
OPEC
EIA
PE
polyethylene
EM
emerging markets
PP
polypropylene
EOR
PSA
E&P
PSC
EPSA
q-o-q
quarter-on-quarter
FID
R&D
FDI
R/P
reserves/production
FEED
RPR
FPSO
SGI
FTA
SoI
statement of intent
FTZ
SPA
GDP
SPR
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AOR
KCTS
G&G
t/d
GoM
Gulf of Mexico
tcm
GS
geological survey
toe
GTL
gas-to-liquids conversion
tpa
GW
gigawatts
TRIPS
GWh
gigawatt hours
trn
trillion
HDPE
T&T
HoA
heads of agreement
TTPC
IEA
TWh
terawatt hours
IGCC
UAE
IOC
USGS
US Geological Survey
IPI
Iran-Pakistan-India Pipeline
WAGP
IPO
WIPO
JOC
WTI
JPDA
WTO
Source: BMI
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Methodology
Industry Forecast Methodology
BMI's industry forecasts are generated using the best-practice techniques of time-series modelling and
causal/econometric modelling. The precise form of model we use varies from industry to industry, in each
case being determined, as per standard practice, by the prevailing features of the industry data being
examined.
Common to our analysis of every industry is the use of vector autoregressions. Vector autoregressions allow
us to forecast a variable using more than the variable's own history as explanatory information. For
example, when forecasting oil prices, we can include information about oil consumption, supply and
capacity.
When forecasting for some of our industry sub-component variables, however, using a variable's own
history is often the most desirable method of analysis. Such single-variable analysis is called univariate
modelling. We use the most common and versatile form of univariate models: the autoregressive moving
average model (ARMA).
In some cases, ARMA techniques are inappropriate because there is insufficient historic data or data quality
is poor. In such cases, we use either traditional decomposition methods or smoothing methods as a basis for
analysis and forecasting.
BMI mainly uses OLS estimators and in order to avoid relying on subjective views and encourage the use
of objective views, BMI uses a 'general-to-specific' method. BMI mainly mainly uses a linear model, but
simple non-linear models, such as the log-linear model, are used when necessary. During periods of
'industry shock', for example poor weather conditions impeding agricultural output, dummy variables are
used to determine the level of impact.
Effective forecasting depends on appropriately selected regression models. BMI selects the best model
according to various different criteria and tests, including but not exclusive to:
Hypothesis testing to ensure coefficients are significant (normally t-test and/or P-value);
All results are assessed to alleviate issues related to auto-correlation and multi-collinearity.
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Human intervention plays a necessary and desirable role in all of BMI's industry forecasting. Experience,
expertise and knowledge of industry data and trends ensure that analysts spot structural breaks, anomalous
data, turning points and seasonal features where a purely mechanical forecasting process would not.
Sector-Specific Methodology
There are a number of principal criteria that drive our forecasts for each energy indicator.
Energy Supply
This covers the supply of crude oil, natural gas, refined oil products and electrical power, which is
determined largely by investment levels, available capacity, plant utilisation rates and national policy. We
therefore examine:
Company-specific capacity data, output targets and capital expenditures, using national, regional and
multinational company sources;
International quotas, guidelines and projections from organisations such as OPEC, IEA, and EIA.
Energy Consumption
A mixture of methods is used to generate demand forecasts, applied as appropriate to each individual
country:
Underlying economic (GDP) growth for individual countries/regions, sourced from BMI published
estimates;
Historic relationships between GDP growth and energy demand growth at an individual country are
analysed and used as the basis for predicting levels of consumption;
Third-party agency projections for regional demand, from organisations such as the IEA, EIA, OPEC;
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Cross Checks
Whenever possible, we compare government and/or third-party agency projections with the declared
spending and capacity expansion plans of the companies operating in each individual country. Where there
are discrepancies, we use company-specific data as physical spending patterns to determine capacity and
supply capability. Similarly, we compare capacity expansion plans and demand projections to check the
energy balance of each country. Where the data suggest imports or exports, we check that necessary
capacity exists or that the required investment in infrastructure is taking place.
Source
Sources include those international bodies mentioned above, such as OPEC, IEA, and EIA, as well as local
energy ministries, official company information, and international and national news, plus international and
national news agencies.
Rewards: Evaluation of sector's size and growth potential in each state, and also broader industry/state
characteristics that may inhibit its development. This is further broken down into two sub categories:
Industry Rewards (this is an industry-specific category taking into account current industry size and
growth forecasts, the openness of market to new entrants and foreign investors, to provide an overall
score for potential returns for investors);
Country Rewards (this is a country-specific category, and the score factors in favourable political and
economic conditions for the industry).
Risks: Evaluation of industry-specific dangers and those emanating from the state's political/economic
profile which call into question the likelihood of anticipated returns being realised over the assessed time
period. This is further broken down into two sub categories:
Industry Risks (this is an industry-specific category whose score covers potential operational risks to
investors, regulatory issues inhibiting the industry, and the relative maturity of a market);
Country Risks (this is a country-specific category in which political and economic instability,
unfavourable legislation and a poor overall business environment are evaluated to provide an overall
score).
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We take a weighted average, combining market and country risks, or industry and country rewards. These
two results in turn provide an overall Risk/Reward Rating, which is used to create our regional ranking
system for the risks and rewards of involvement in a specific industry in a particular country.
For each category and sub-category, each state is scored out of 100 (with 100 the best), with the overall
Risk/Reward Rating a weighted average of the total score. Importantly, as most of the countries and
territories evaluated are considered by BMI to be 'emerging markets', our rating is revised on a quarterly
basis. This ensures that the rating draws on the latest information and data across our broad range of
sources, and the expertise of our analysts.
BMI's approach in assessing the risk/reward balance for infrastructure industry investors globally is
fourfold:
First, we identify factors (in terms of current industry/country trends and forecast industry/country
growth) that represent opportunities to would-be investors;
Second, we identify country and industry-specific traits that pose or could pose operational risks to
would-be investors;
Third, we attempt, where possible, to identify objective indicators that may serve as proxies for issues/
trends to avoid subjectivity;
Finally, we use BMI's proprietary Country Risk Ratings (CRR) in a nuanced manner to ensure that only
the aspects most relevant to the infrastructure industry are incorporated. Overall, the system offers an
industry-leading, comparative insight into the opportunities/risks for companies across the globe.
Sector-Specific Methodology
BMI's approach in assessing the risk/reward balance for oil and gas industry investors is threefold:
First, we have disaggregated the upstream (oil and gas E&P) and downstream (oil refining and marketing,
gas processing and distribution), enabling us to take a more nuanced approach to analysing the potential
in each segment, and identifying the different risks along the value chain.
Second, we have identified objective indicators that may serve as proxies for issues and trends that were
previously evaluated on a subjective basis.
Finally, we have used BMI's proprietary Country Risk Ratings in a more refined manner in order to
ensure that only those risks most relevant to the industry have been included.
Conceptually, the ratings system is organised in a manner that enables us clearly to present the comparative
strengths and weaknesses of each state. The headline oil and gas rating is the principal rating. However, the
differentiation of upstream and downstream and the articulation of the elements that comprise each segment
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enable more sophisticated conclusions to be drawn, and also facilitate the use of the ratings by clients who
have varying levels of exposure and risk appetite.
Oil & Gas Risk/Reward Rating: This is the overall rating, which comprises 50% upstream and 50%
downstream;
Upstream Oil & Gas Risk/Reward Rating: This is the overall upstream rating, which is composed of
rewards/risks (see below);
Downstream Oil & Gas Risk/Reward Rating: This is the overall downstream rating, which comprises
rewards/risks (see below).
The following indicators have been used. Overall, the rating uses three subjectively measured indicators and
41 separate indicators/datasets.
Indicator
Rationale
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Indicator
Rationale
Industry risks
Licensing terms
Privatisation trend
Country risks
Physical infrastructure
Rule of law
Corruption
Source: BMI
Weighting
Given the number of indicators/datasets used, it would be inappropriate to give all sub-components equal
weight. Consequently, the following weighting has been adopted:
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Table: Weighting
Component
Upstream RRR
Rewards
Weighting (%)
50, of which
70 of Upstream RRR, of which
- Industry rewards
75
- Country rewards
25
Risks
- Industry risks
65
- Country risks
35
Downstream RRR
Rewards
- Industry rewards
75
- Country rewards
25
Risks
30, of which
- Industry risks
60
- Country risks
40
Source: BMI
Page 137