Archives for category: Offshore Vessel Registers

The mobile offshore orderbook reached its lowest level since 2005 at the start of August. Furthermore, a significant portion has been on order for a number of years, with a large share of these units having already been launched. As uncertainty continues to cloud the future for many of these vessels, this month’s Analysis investigates the nature of the offshore orderbook in more detail.

For the full version of this article, please go to Offshore Intelligence Network.

Vietnam has the third largest proven oil reserves in the Asia Pacific region – but much of its existing offshore production is from declining shallow water fields. So the country’s first deepwater discovery, made in October, is a potentially exciting development. Could deepwater E&P activity in Vietnam be set to take off, or will weak oil prices and disputes over territorial waters prove problematic?

Shallow Beginnings

Most of Vietnam’s 0.28m bpd of offshore oil and 0.99bn cfd of offshore gas production is derived from fields in the Nam Con Son and Cuu Long basins, all of which are in less than 200m of water. The Cuu Long basin is perhaps the most successful area off Vietnam as it is home to many large fields, including Bach Ho, Su Tu Vang and Rang Dong. The dominance of shallow fields has skewed development towards fixed platforms. 88% of all active Vietnamese fields are exploited as such. Of these fields, the Bach Ho field accounts for 34 cor 37% of the total found on active fields.

Operators in Vietnam mainly consist of local and regional NOCs as well as IOCs (most commonly via joint operating companies in partnership with Petrovietnam). While significant market reforms have increased foreign investment in Vietnam’s offshore sector, further improvements to its transaction and tax systems could quicken the pace of foreign participation in the future.

Wading Into Deeper Waters

No significant shallow discoveries have been made recently, meaning that there is little to offset Vietnam’s depleting shallow water reserves. This highlights the need to break into deepwater frontiers, which could hold substantial levels of undiscovered hydrocarbons. The VGP-131-TB well, Vietnam’s first discovery in water depths >500m, was drilled in October 2015 by the Vietgazprom JOC, at depths of 1,600m in the Saigon basin. The ultra-deep find could provide momentum for Vietnam’s push into deepwater exploration. However, unlike China, which is able to independently bring deepwater fields like the Lingshui 17-2 online, Vietnam could still need to rely on foreign cooperation to jointly develop such finds in the short term.

Shaky Prospects

Vietnam’s hydrocarbon resources mainly lie in the South China Sea, with the most recent discovery at the southern end. The sea is an area of multiple disputed territorial claims by many countries, including China. This could impede any deep developments, if international partners were to view overlapping sovereignty claims to be an excessive business risk. Perhaps more importantly though, the post-downturn attitude of IOCs is one of cost-consciousness given lacklustre economic conditions. This could skew near-term interest towards safer EOR projects instead of unproven deeper water development in the South China Sea.

Since Vietnam’s historical track record is in shallow waters, even if further deepwater discoveries are forthcoming, then the chance of rapid deepwater developments in the South China Sea is probably going to take time. It is likely to need outside expertise, and the current energy markets may well not be conducive to this. That said, the discovery of Vietnam’s first deepwater field marks a new chapter in the country’s oil and gas story.

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A sustained period of low oil prices has created a shortfall in offshore support vessel (OSV) demand, at a time when the sector has displayed rapid fleet expansion. Charter rates have fallen significantly, whilst the number of inactive vessels has reached record levels in some regions. An increase in vessel scrapping would seem to be an obvious solution to this problem, so why hasn’t this been the case so far?

Mirror The MODU Model?

OSV demand has fallen – at least 11% of the total fleet was laid up at start September. So far in 2015, 23 removals have been recorded from the OSV fleet (18 AHTS/AHT and 5 PSV/Supply vessels). For AHTS/AHTs this is a 29% increase on 2014 on an annualised basis. PSV removals, however, are down by 46%. In either case, the number of removals seems below what might be expected given the challenging market conditions.

For the AHTS sector in particular, rig moves provide an invaluable source of demand – a decrease in utilisation for these units has not been surprising given the sharp fall in E&P expenditure following the drop in oil prices. Oversupply is also a significant issue for the MODU market. However, the reaction from owners in that sector has been very different, as is evident from a net decrease of 15 units from the fleet so far in 2015.

The decrease in MODU numbers has been achieved in two ways. Firstly, by reducing the number of existing units – removals are currently up by 94% in 2015 on an annualised basis, already surpassing the record number of removals recorded for any full year. Secondly, the addition of newbuilds has been restricted, with the number of deliveries down by 39% in annualised terms in 2015.

Short-Term Gains

A likely reason for the low uptake in OSV removals relative to the MODU sector is that there is comparatively more value in scrapping rigs (in particular, floaters), compared to OSVs, on account of their larger size and steel content. Furthermore, it is relatively easy and cost-effective to lay-up or stack OSVs, which has been the preferred option for owners – at least 340 AHTSs and 254 PSVs are estimated to be laid up, although in reality this number may be even greater. Similarly, the sale of vessels for use in other sectors (e.g. utility support) provides some means of reducing active vessel numbers, although sales activity for OSVs in 2015 is currently down by 25% on an annualised basis.

However, whilst stacking of OSVs provides some respite for owners during times of oversupply, it can only be considered a short-term solution – especially given the size of the current OSV orderbook: the number of OSVs on order is equivalent to 11% of the active fleet and, although some slippage is expected, 293 units are slated for delivery by end 2015.

Long-Term Woes

The OSV dayrate index has fallen by 27% since the start of 2015 and, with no significant upturn in oil prices looking likely, pressures seem set to continue. Fleet growth stands at 2.3% y-o-y, and the issue of OSV oversupply is expected to remain significant. Against this background, the discussion of removals is likely to be ongoing theme.

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Since 1970, 179 offshore gas fields have been discovered in the Browse and Carnarvon Basins of Australia’s Northwest Shelf. From around 2005, as offshore technology advanced and Asian gas demand rose, operators hatched plans of monstrous magnitudes for these fields. However, in an environment of low oil prices and E&P spending cuts, some of these offshore behemoths now look more endangered.

Taming The Seas

The Australian NW Shelf accounts for about 15% of offshore projects globally with CAPEX of over $5bn. NW Shelf projects tend to be capital intensive, in part because they are remote, with an average distance to shore of 161km. Development thus entails long export pipelines (889km for Ichthys, for example) to onshore LNG plants, or as yet unproven FLNG technology. CAPEX in turn contributes to high project breakeven prices, as does OPEX: for example, OSVs make longer trips for far-from-shore projects. Until recently, high project breakevens stymied final investment decisions (FIDs). However, due in part to cost-saving subsea and cryo-technology, in 2007, Chevron approved Greater Gorgon, a $37bn multi-field project with reserves of 40 tcf. Subsequently, 11 more projects received positive FIDS, including Prelude ($12bn), Pluto ($16bn) and Wheatstone ($29bn).

Teething Problems

Since 2007, 4 of these projects have come onstream and the other 8 are due to begin ramping up 2015-17. However, these 12 projects have not been without their problems. Greater Gorgon, for instance, was first scheduled to start up in 2H 2014, rather than 2H 2015; CAPEX has risen by 49% to $55bn. Meanwhile projects yet to be sanctioned have seen FIDs delayed by operators trying to cut costs. Scarborough, a mooted $19bn FLNG development 286km from shore (which has now been delayed again due to the fall in the oil price) underwent multiple FEED studies following the 2010 pre-FEED. Before circumstances changed, a 2019 start-up briefly looked likely.

Monsters Have Feelings Too

NW Shelf gas projects are thought to be some of the more sensitive globally to the change in the oil price since mid-2014. Greater Gorgon’s breakeven is relatively low for the area, but still stands at $67/boe. Projects further from shore are thought to have higher breakevens, in the $80-100/boe range. No Australian project more than 250km from shore has passed FID, though 50% of those yet to reach EPC exceed this distance, casting doubts on their viability. Since the fall in the oil price, Scarborough’s FID has been postponed to 2017/18; start-up before 2023 is considered unlikely. Other projects facing fresh feasibility concerns include Equus, Browse, Greater Sunrise, Crux and Cash Maple. Indeed, the average slippage for such projects already stands at 40 months. Many may not now come onstream before 2023 and a paucity of start-ups is anticipated in the mid-term, 2018-22, due to delayed FIDs 2014-17.

Clearly, then, remote Australian mega-projects are subject to high costs and breakevens, which increases slippage risk. That being said, the long-term fundamentals of energy-hungry non-OECD economies still suggest remaining NW Shelf gas will be viable eventually. These mammoth projects are not extinct yet.

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