Archives for posts with tag: Offshore Intelligence Monthly

The year just gone was a mixed one for offshore. Incremental progress continued towards rebalancing, while some sectors saw small day rate improvements compared to 2017. Overall though, challenges persisted in an oil price environment characterised by uncertainty and volatility. Several key indicators underperformed relative to start year sentiment and the year ended on something of a negative note.

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

Following the recent oil price plunge, US shale oil production growth has been in the headlines once again, this time as one of the main factors behind the latest slide in oil prices. However, it can still be tricky to appreciate just how significant US shale oil output has now become to global oil markets. Comparing this year’s surge in output against some offshore benchmarks can be helpful.

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

Offshore is quite a project driven sector in the sense that work at offshore fields drives much of the demand for offshore vessels. But offshore is also project driven in the sense that offshore output growth is linked to field project start-ups. And since 28% of global oil production is offshore, the aggregate of individual offshore start-ups can potentially have significant implications for wider energy market trends…

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

West Africa, which accounts for 16% of global offshore oil production, has been perhaps the most challenged region in the offshore downturn. Rig utilisation, for example, fell to a lower level (48%) than in any other region. But with oil prices currently back in the $70-$80/bbl range, there are some signs that things could be picking up, not least Total’s recent FID at the $1.2bn Zinia Ph.2 deepwater project off Angola.

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


The current conventional wisdom is that the market for subsea installation and maintenance is slightly more insulated from the worst effects of the oil price fall, given the long project timelines and high capex involved. But with new short-term investment set to be cut, and reports of declining vessel utilisation, it seems likely that the potentially positive longer-term trend will be preceded by short-term challenges.

Subsea Construction

A key indicator of subsea construction demand is the backlog for EPC work held by major subsea companies. The growth rate of this year-on-year is shown on the graph (red line). Broadly, this follows the oil price, going into negative territory in Q1 2015, just as it did during 2009.

The remaining two lines on the graph show the year-on-year growth in two parts of the fleet related to subsea construction and subsea support. Growth in both accelerated in 2009 (albeit from a relatively small fleet). A rush of deliveries hit the wrong part of the market cycle and exacerbated the demand weakness caused by the 2009 oil price drop. It is also noticeable that, back then, the growth of the support fleet was more rapid than growth in the fleet of the larger construction assets, despite the fact that the IMR fleet was already 91% larger.

Calm Beneath The Storm?

Of course, the key question now is: will it happen again? The industry is likely to have to weather multiple quarters of declining backlog given that oil price weakness is discouraging IOCs, whilst another major demand source, Petrobras, clearly has issues to resolve. Unfortunately, the answer is, to some degree, yes. Ordering in the last few years means that fleet growth is set to accelerate in 2015.

So will it matter? Again, the answer may well be yes, in the short term. Few would deny that all markets, including subsea, face short-term challenges. However, the longer-term fundamentals give cause for optimism. As subsea well completions age, their maintenance requirements are likely to increase. A decade ago, 15% of installed subsea wells were over 15 years of age: today 35% are, and the volume of such “middle-aged” subsea structures has been growing at 20% per annum. This is a supportive trend for the longer-term future of the IMR fleet, whilst those assets focussed on new construction are more dependent on the fortunes of EPC companies’ backlogs, which, as shown below, are currently in decline.

Beneath The Waves

A wildcard which may help the IMR fleet is the share of smaller-craned units ordered by new, Asian players. The Asian share of the MSV orderbook is now 25%: double that in 2005. The largest areas for subsea production (the North Sea, Brazil, West Africa) are in the Atlantic. If operators there take an attitude of preferring more experienced subsea owners, this could constrain vessel supply in the Atlantic more than the orderbook picture would suggest.

So, weaker markets are already very evident, with declining backlogs, idle vessels and companies announcing job cuts. Yet there are reasons to be optimistic about the longer term future, particularly for maintenance requirements. However, the market will clearly first have to surmount a short-term future of excess supply and muted demand.


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.