Archives for posts with tag: offshore exploration

Since the onset of the downturn in 2014 it has been a pretty bleak few years for the offshore sector, with the occasional chinks of light on the horizon often quickly clouded over. More recently there have been indications that things might be clearing up a little and so sentiment has improved somewhat. But it is worth recalling just how low the barometer has sunk in order to put these things in perspective.

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

The African continent accounts for 16% (490) of active offshore fields and 17% (535) of offshore fields that are either under development or are potential developments globally. It is also home to key offshore exploration frontiers. However, the nature of E&P activity varies widely across the continent, as is clear from analysing the offshore areas into which Africa can be divided: North, South, East and West Africa.

North Africa: Old Fields?

A total of 217 oil or gas fields are located offshore North Africa, of which 112 are in production (95% in shallow waters). In this mature area, offshore oil production is projected to stand at 0.34m bpd in 2016, down 37% on the area’s peak of 0.54m bpd in 1991. Bar the possible restoration of offshore oil production lost in the “Arab Spring”, decline is set to continue. However, North African offshore gas production still has significant growth potential, forecast as it is to grow with a CAGR of 8.4% from 4.29bn cfd in 2016 to stand at 8.86bn cfd in 2025. This projected growth is driven by gas projects such as Zohr Ph.1 ($3.5bn; 1bn cfd) and Ph.2 ($10bn; 7bn cfd). The Zohr field, a frontier find in a water depth of 1,450m in the Levantine Basin, exemplifies the ongoing rise of deepwater E&P in the area.

South Africa: Few Fields

South African offshore production is minute in a global context. The area is home to just 17 offshore fields (only seven active, two having shut down in 2013). Although not without potential, E&P in the area has stalled in the downturn, as IOCs have cut and reprioritised E&P spending.

East Africa: New Fields

Unlike North and West Africa, East Africa has little history of offshore E&P: 88% of the area’s 41 offshore fields were discovered after 2009. The average water depth of these “frontier” finds is 1,570m and 92% are gas fields (with total reserves of more than 168 tcf). Offshore gas production in the area is projected to hit 2.82bn cfd in 2025 (from 0.13bn cfd in 2016) as fields are developed as part of LNG projects such as Coral FLNG Ph.1 ($7bn; 0.433bn cfd). However, further FID slippage at these frontier projects is a risk in the weaker energy price environment.

West Africa: Costly Fields?

West Africa constitutes one corner of the ‘Golden Triangle’ of deepwater E&P: of the 368 active fields in the area, 83% are in shallow waters (in the Gulf of Guinea and Angola) but 43% of 364 potential developments are in depths of more than 500m. The area has major deepwater production growth potential, even though it already accounted for 17% (4.35m bpd) of global offshore oil production in 2015. However, West Africa is a key offshore ‘swing’ region in terms of CAPEX and production: planned FPSO hubs such as MDA (Angola) tend to have high breakevens (c.$70/bbl+), so project FIDs have been scant since 2014. Frontier finds from Ghana up to Mauritania (39 since 2009) could yield more viable production growth though, and exploration in these waters has continued in the downturn.

In conclusion then, the African continent is home to a range of offshore field and project trends. Although there are some similarities across the continent in terms of “frontier” E&P, water depths and other factors, to get a grip on African offshore E&P, it is necessary to take the full range of available data and “drill down” into it.

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Two high-level indicators of vessel and structure demand in the offshore sector are energy prices and oil company E&P spending. A third, slightly more specific indicator is estimated offshore project capital expenditure, or CAPEX. While this metric does not capture demand arising from, for example, offshore exploration campaigns, it can be a key proxy for demand resulting from offshore EPC activity.

CAPEX Defined

Since the start of 2010, around $980bn of CAPEX has been committed to some 669 offshore projects globally. But just what makes up offshore project CAPEX? As defined herein, it consists of estimated capital invested in the development, redevelopment or decommissioning of offshore fields; it excludes spending on licensing rounds, seismic surveys and exploration wells, as well as operational expenditure arising from manning and IMR at active fields. CAPEX is committed via EPC contracts, usually issued soon after a project final investment decision (FID), for items such as MOPUs, fixed platforms, pipelines and subsea trees, as well as support, installation and development drilling services. CAPEX also translates into field developments that create durable demand for OSVs. CAPEX data collected by Clarksons Research is as specified by project operators; where no definitive figure is given, estimates are derived from assessment of comparable projects with known CAPEX.

Measuring CAPEX

One advantage of CAPEX as a metric is that, unlike a count of project FIDs, it reflects the differing ‘weight’ of projects. Indeed, project CAPEX can vary by several orders of magnitude. The B-173A Expansion project off India, for example, entailed the installation of a second shallow water fixed platform on the B-173A gas field. The project, which started up in 2015, had a reported price tag of $67m. In contrast, the ongoing 230,000 bpd Kaombo Ph.1 development off Angola has a reported CAPEX of $16bn. This wide variation in costs helps to explain recent CAPEX trends. During the 2011 to 2013 boom years, estimated CAPEX averaged $204bn p.a. globally, supported by high energy prices and rising E&P budgets. As oil prices tumbled in 2014, CAPEX fell by 54% y-o-y. CAPEX in 2015 was steady on 2014, even though FIDs fell by 41%, as a few giant projects with low breakevens, such as Johan Sverdrup (Norway, $12bn) and WND Ph.1 (Egypt, $12bn), received FIDs. However, other FIDs have continued to slip in the downturn. CAPEX so far in 2016 stands at around $40bn, down 34% y-o-y on an annualised basis.

CAPEX As An Indicator

As offshore CAPEX has fallen, EPC tendering has suffered, and hence, for example, MOPU newbuild contracting has dropped from an average of 18 units p.a. in 2010 to 2013, to just eight units in 2015 and two in 2016 to date. Similarly, 16 pipelayers were contracted in the same period, but only one unit has been ordered since 2013, reflecting depressed utilisation and earnings. Until CAPEX begins to increase once more, these sectors are likely to remain challenged.

In terms of spotting a recovery, then, it is worth keeping an eye on oil companies’ offshore project CAPEX plans. For not only is CAPEX one of a range of factors affecting offshore markets; it is a useful indicator with particular relevance to EPC-led vessel activity and investment too.

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As a result of weaker oil prices and E&P spending cuts, offshore exploration is severely challenged. This is reflected in the fact that discoveries are down 47% y-o-y on an annualised basis so far in 2016, global rig utilisation has dropped 22 percentage points to 73% in two years, and 29% of seismic units are inactive. But it is also reflected in a perhaps less prominent element of exploration, namely, block awards.

Block Basics

The basic framework for offshore exploration is provided by blocks. Blocks are areas in which specific oil companies (the licensees) have set E&P rights and obligations with respect to one another and the host country over a specified period. As at April 2016, oil companies hold 10,968 offshore blocks (with an average area of 996 km2) globally. As a general rule, each block will have an operator company, but also several more companies with equity in the block. This allows oil companies to spread the risks of E&P.

Blocks may be awarded to oil companies on a one-off basis but are usually awarded through well-publicised, semi-regular licensing rounds, for example Norway’s ongoing ‘23rd Licensing Round’. Indeed, at present eight offshore rounds are in progress, covering 55 blocks. However, oil company uptake is looking lacklustre and it is expected that, given low levels of interest, a very small percentage of these will be awarded. Just 102 offshore blocks have been awarded so far in 2016, down 38% y-o-y on an annualised basis on a poor 2015. By way of comparison, 1,162 offshore blocks were awarded in 2013.

Acreage Accumulation

In part, this situation reflects reduced E&P spending (exploration budgets are relatively easy to cut). But it also reflects something of a block ‘asset bubble’ in the 2010 to 2014 period, in which 5.99 million km2 of offshore acreage was awarded. Supported by a high and stable oil price, many oil companies stocked up on frontier acreage, engaging in bidding wars for key blocks, driving up prices. For example, in a battle for a 8.5% share in Area 1 off Mozambique in 2012, the block was implicitly valued at c.$14 billion (and East Africa was just one of several frontiers opened up in this period). Oil companies thus acquired a great deal of relatively costly offshore acreage in a short period.

Exploration Excesses

On the plus side, the exploration boom of 2010 to 2014 yielded 765 offshore discoveries, including many large finds that are likely to drive future offshore production growth. However, block oversupply, analogous to that in segments of the offshore fleet, built up. As the two graphs show, the peak of the latest block awards cycle coincided with a 2013 peak in ordering of rigs (117 units) and seismic capacity (104 streamers). Just as there is a supply-demand imbalance in the seismic and rig markets, so too is there in blocks. Oil companies are now sitting on a backlog of unexplored blocks, with fewer incentives to bid for new acreage (though strategic investment in Iran or deepwater Mexico might still happen).

So licensing reflects the broader exploration situation, with block awards and vessel contracting showing similar trends. This being the case, a future rise in block awards could perhaps presage a general recovery in exploration. In gauging exploration sentiment then, upcoming licensing rounds could well be worth monitoring.

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