Archives for posts with tag: offshore technology

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.

OIMT201509

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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