Archives for posts with tag: offshore fields development

Well, 2015 was really quite a year. Brent opened in January at c.$49/bbl, the price having tumbled in Q4 2014; the subsequent rally, which saw it pass $65/bbl, was cut short, and in December, it fell past $37/bbl. Expectations of a brief correction were confounded, and with E&P cuts biting and oil still falling, offshore seems to be facing a multi-year downturn. But just how does 2015 compare to recent years?
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Annus Horribilis

At the end of 2015, Brent stood at around $37/bbl, far below the $60-80/bbl envisaged by many analysts at the close of 2014. Through 2015, various factors conspired to maintain a supply glut and depress the price, including OPEC policy, the resilience of the US shale sector and the softening global economic outlook.

Oil companies reacted to weaker price expectations by cutting E&P budgets and slashing jobs. In the offshore space, oil companies cut E&P spending by around 19% on average. Exploration spending was hit particularly hard, but FIDs at offshore development projects in 2015 were also down approximately 49% y-o-y, as operators were reluctant to commit capital to long lead-time projects. Some offshore areas and fleet segments fared relatively better than others, but 2015 was a pretty bleak year overall.

Turbulent Waters

In terms of offshore field activity, 2015 was the worst year in over a decade. Although some 2015 offshore discoveries like Zohr and Hopkins were notable for their magnitude or fast-track potential, just 96 offshore fields were discovered globally in 2015, down 19% on 2014 and 41% on the 2005-14 average of 162 discoveries per annum.

Meanwhile, only 68 offshore fields started up in 2015, down 41% on both the 114 start-ups of 2014 and the 2005-14 average. In part, this reflected problems pre-dating the fall in the oil price, such as slippage, cost inflation and political risk in countries like Nigeria, Egypt and Brazil. However, due to the paucity of FIDs in 2015, the backlog of fields under development at start 2016 was down roughly 11% y-o-y, even with many planned 2015 field start-ups deferred into 2016 due to slippage. The subsea tree backlog also fell by around 19%, to 301 units.

Challenging Times

The fall-off in offshore field activity compounded developing supply-demand imbalances in the offshore fleet, most notably in the OSV and rig fleets, with an adverse effect on utilization and rates. Thus global rig utilization stood at 73% at end 2015, compared to 87% at end 2014 and 96% at end 2013. Day rates also diminished substantially, with high-spec drillships in the US GoM, for example, commanding $200-275,000/day at end 2015, compared to $600,000/day at the peak of the market cycle. In the OSV sector, falling rig moves and project activity helped depress rates: the North Sea term rate for an AHTS 20,000+ BHP, for instance, averaged $16,800/day, down 52% y-o-y. Moreover, many OSV owners felt compelled to lay up units – a trend still playing out. Offshore newbuild contracting suffered, too with contracting down by 68% on 2014, so that even with delivery delays, the orderbook at start 2016 stood at 1,157 units, down 26% on start 2015.

Troubling Portents

Thus in comparison to the last ten years, and the recent market peak in 2013/14 in particular, 2015 was challenging. The coming year is likely to be a tough one as well, with many energy companies set to make further E&P budget cuts of 20-40% and the oil price seemingly yet to bottom out. The halcyon days of $100+/bbl now seem like a long time ago indeed.

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The rigid pipe layer fleet is complex, varied and sometimes perplexing: S-lay, J-lay, reel-lay; barge, vessel, semi-sub; tensioners, carousels, moonpools – units therein defy easy comparison with one another. And so, unlike in many sectors of the offshore fleet, it is not immediately clear what is a ‘high-spec’ and what a ‘low-spec’ unit. What is needed, then, is a framework to analyse the 172-strong pipe layer fleet…

Offshore Operations

In essence, pipe layers are used to install rigid pipelines on the seabed, primarily during the development of offshore fields. These pipelines are used to export oil/gas to shore, or to transport fluids between seabed or surface installations within a project area. Pipe laying is conducted during the EPC phase of project development, consequent on award of (typically lump-sum) EPIC and SURF contracts, usually to specialist offshore construction companies like Allseas, McDermott, Saipem, Subsea7 or Technip, who own 4, 5, 14, 6 and 6 pipe layers respectively – 20% of the fleet. There is no pipe layer spot market as such, so comparing day rates to pick out the high-spec from low-spec units is not possible.

Inscrutable Idiosyncrasy?

Vessels’ traits are not immediately helpful either. Monohull structures account for 19% of units and barge/semi-sub structures for 81%. Pipe sections are welded on-board and deployed via J-Lay towers (8% of units) or S-Lay stingers (76%), the letter indicating the curvature of the pipeline as it is lowered to the sea floor. However, 3% of vessels have both J-Lay and S-Lay structures; 16% use cranes or have hybrid, reel-lay systems; and the tensioner capacities of lay systems (i.e. the weight of pipeline they can support) range from under 10mT up to 2,000mT. There is no simple correlation between a single feature and a unit’s capabilities: “Lorelay” has tensioners of 265mT, yet cannot lay pipes in ultra-deepwaters; “C Master”, with tensioners of 160mT, can. The secondary functions of units can also vary greatly: 10% of units have ROV capabilities, for example. Moreover, 19% of units in the flexi-lay fleet can install rigid pipelines (and 5% vice versa). How then, amidst this variation, to distinguish a ‘high-spec’ from a ‘low-spec’ pipe layer?

A Promising Perspective

One way is to cross reference the maximum pipe lay water depth of units with the maximum diameter of pipe they can lay. Thus the 12 units in the “red” segment of the inset chart (e.g. “Seven Borealis” and “Sapura 3000”) could be considered high-spec and versatile, competing with units in the “dark blue” segment for ultra-deepwater subsea contracts, but with the “light blue” segment for large export pipelines in shallower waters. In the opposite quarter of the matrix, the 55 “grey” units are mostly barges, deployed in shallow waters like the Niger Delta and Lake Maracaibo. One could say there are four (overlapping) markets for pipe layer work. The range of EPC contracts for which construction companies are likely to bid will depend in part on the segmentation of their pipe layer fleets.

So, pipe layers have an array of characteristics complicating segmentation. However, some units are clearly better suited to some projects than others. By cross-referencing factors like water depth with pipe width, one can craft a framework for sorting through this diverse fleet.

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