Archives for posts with tag: offshore activity

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.

On July 14th 2015, after 20 months of negotiations, Iran and the so-called “P5+1” signed the “Joint Comprehensive Plan of Action”: in return for US, EU and UN-mandated sanctions against the country being gradually lifted, Iran has agreed to roll back its nuclear capabilities. Should the deal stick, the door will open to foreign investment once more. What, then, are the possible implications for Iranian offshore oil? Should this deal stick, IOCs will soon be able to operate in Iran once more. What, then, are the possible implications for Iran’s offshore sector?

Political Locks

On the eve of the Islamic Revolution in 1979, total Iranian oil production stood at 6.0m bpd, of which around 12% (0.72m bpd) was from 13 offshore fields producing oil, all located in shallow waters and exploited via fixed platforms. The turmoil of the Revolution saw oil production drop to 1.70m bpd in 1980, and in the ensuing Iran-Iraq War, offshore fields like Salman were shut in due to military action. As a result, actual offshore oil production was less than 50% of capacity for most of the 1980s; after the War, production began to recover, peaking at 88% of capacity (0.60m bpd) in 1997. However, as US and then EU economic sanctions on Iran tightened, IOCs were forced to exit the country, depriving Iran’s offshore sector of key investment and technology. Development work slowed and much of Iran’s offshore 2P reserves (30.3bn bbl of oil; 707 tcf of gas) were locked away. At the same time, Iran lacked the resources to implement EOR at brownfields. As a result, the gap between actual and nameplate offshore production was 1.38m bpd by 2014, with production at 0.54m bpd.

Rusty Hinges

Now that sanctions are to be lifted, indications suggest Iran aims to get as much oil production as possible back onstream in 2015/16. Restoring offshore production is likely to require more than just turning the taps though. Iran’s ability to halt decline at brownfields has been curbed, in contrast to other mature producers like the U.A.E. Half of Iran’s active offshore oil fields predate the Revolution (the oldest started up in 1961). Extensive EOR work is likely to be required at such fields – one opportunity for IOCs. Thus, while offshore production is forecast to grow by 7.3% in 2015, this is mostly due to South Pars condensate production ramping up, rather than utilisation of older capacity.

An Alternative Entrance?

Iran is planning an “oil contract roadshow” in London in 2H 2015, with the stated aim of attracting foreign investment in E&P of $185 billion by 2020. However, it is likely that much of the investment will be directed towards stalled onshore projects such as Yadavaran, and to restoring production at mature onshore fields like Azadegan. A spate of onshore discoveries made from 2006 to 2008 may also be prioritised by cash-hungry Iran, particularly those in the Khuzestan province spanning the Iraq border. Some of Iran’s 7 undeveloped offshore fields like Esfandiar (532m bbl) may warrant priority, and the South Pars Oil Layer is scheduled to come onstream in 2018. But even taking into account the Caspian (home to the 2011 Sardar-e Jangal 500m bbl find), offshore oil opportunities for IOCs (and so vessel owners) may be limited at first.

It seems, then, that the offshore oil capacity gap could widen before it narrows. Certainly given its reserves Iran has long-term offshore potential, notwithstanding its troubled history. But observers expecting a quick and big uptick in oil-related offshore activity might need to be patient.

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E&P offshore India can be divided into two very distinct species of activity: the one species is typified by shallow water exploration using jack-up drilling rigs, and by multi-phase fixed platform developments; the other species by ultra-deepwater exploration using floaters. The first is concentrated off the west coast, the second off the east coast. But when it comes to CAPEX, which species of activity sits at the top of the food chain in these lean times?

Shallow Water Ancestry

Mumbai High is the ancestor and primordial archetype of the vast majority of field developments offshore India today. Discovered in 1974 in the Mumbai Basin off the country’s west coast, the field was brought onstream in 1976 and was initially exploited via 4 fixed platforms in water depths of around 85m. Subsequent expansions have seen this number rise to 159, with 8 more platforms being fabricated for the Ph.3 redevelopment projects at the field. For the first 30 years of Indian offshore E&P, exploration was focused in the Mumbai Basin while development followed the pattern at Mumbai High. Hence, as of July 2015, 94 fields had been discovered off India’s west coast, all in shallow waters, accounting for 48% of Indian offshore discoveries. Of these 94 fields, 39 are active and 11 are under development. The basin also accounts for 301 active fixed platforms, as well as 13% (18 units) of the jack-up fleet in the Middle East/ISC region. With EOR and redevelopment work underway, the Mumbai Basin remains an important area of offshore activity.

Deepwater Diversification

However, since 2002 the Indian offshore sector has bifurcated to produce a very different species of offshore activity. Exploration campaigns in the east coast Krishna Godavari Basin resulted in 50 new discoveries in water depths >500m (and 51 shallow water finds). Amongst these was KG-DWN-2005/1-A, a field in a water depth of 3,166m, making it the deepest find (in terms of water depth) to date globally. At the height of KG Basin exploration, 12 floaters were active in the country. All this being said, Indian deepwater activity is much less advanced than shallow water E&P: just two deepwater fields are in production and none are currently under development. As a corollary, there are almost no subsea installations offshore India and just one active MOPU.

An Evolutionary Hiatus?

There are, however, 25 ‘probable’ deepwater field developments, including some potentially prolific fields. However, development seems to have been inhibited by the example of KG-D6 (Dhirubhai 1&3), a deepwater (850m) gas field which has shown precipitous production decline. India’s offshore sector is also dominated by indigenous companies like the government-controlled ONGC, who seemingly lack the deepwater technological or operational expertise of many IOCs. At the same time, there are still 88 potential shallow water fields, as well as plenty of scope for EOR at older fields – the sort of projects where Indian oil companies have substantial experience.

Opening up of the upstream sector, as is being attempted in Mexico, might be one means to adapt to the challenges of the “P” of deepwater E&P in India. However, this does not appear to be on the cards for the immediate future. So for the time being, given the hostile conditions of the weaker oil price environment, shallow water activity seems set to thrive best.

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