Archives for posts with tag: offshore fields

The global fixed platform “fleet” consists of over 7,700 installed structures, equivalent in unit terms to 58% of the mobile offshore fleet. Yet the significant role played by fixed platforms in generating requirement for offshore vessels and services (such as platform installation and IMR) is at times overshadowed by the role of the mobile offshore fleet. So what, then, is the current outlook for the fixed platform sector?

Back To Basics

Fixed platforms are immobile structures that are attached to the seabed and used to exploit offshore fields. All but 32 fixed platforms are located in water depths of less than 200m and the average water depth of the 7,744 installed units is 42m. Platforms usually consist of a ‘jacket’ (the legs) and ‘topsides’ (the decks), and are fabricated from steel, though concrete or wood have been used. Indeed, the first ever fixed platforms were wooden structures off California in the 1930s; these have been dismantled, but North America still accounts for 31% of the fixed platform “fleet”, a legacy of shallow water E&P in the GoM. Other major historical areas of fixed platform installation include the Middle East/ISC (15% of the fleet), SE Asia (22%) and the North Sea (7%). The North Sea is home to most larger structures, such as the 898,000t “Gullfaks C” gravity base platform. Most structures in areas like the Middle East and the US GoM, meanwhile, are at the opposite end of the scale – unmanned monopod/tripod wellhead platforms of less than 100t.

Construction Crunch

Historically, fixed platforms have been a core business area for a number of fabrication yards and EPCI companies. Installation of small structures tends to involve units like liftboats in the US GoM and crane barges in the Middle East. Larger structures (in the North Sea or West Africa) have required more robust transportation and heavy-lift vessels. At present though, the fabrication and installation outlook is subdued. As shown in the inset graph, 96 platforms were ordered in 2014, down 49% y-o-y; in 2015, 42 were ordered, down another 56% y-o-y. Most ordering has been for smaller units in the Middle East (14%, 2014-15) and SE Asia (39%): platforms like the 43,700t “Johan Sverdrup CPP” (North Sea) are exceptional. Reduced contracting is partly due to the weaker oil price, but it also reflects a longer term shift towards subsea developments and deepwater E&P.

A Shift To Services?

It seems, then, that outside of expansion projects in a few areas, the near term demand generated by fixed platforms is likely to be mainly from servicing existing units: facilities need maintaining, paint needs reapplication and so on. For example, long-term, multi-field IMR contracts have reportedly been awarded for platforms in the UK and Saudi Arabia in recent months. PSV and helicopter demand to supply manned platforms (and ERRV demand in the North Sea) will also persist unless fields are shut down. And even then, potential exists in platform removal: there are currently five planned decommissioning projects involving platforms, each project with a value of c.$400m.

So the fixed platform construction market is fairly challenged. But there are other ways in which fixed platforms can create opportunities. These may be quite niche or oblige EPCI companies to adapt, but with 7,744 units in place, the sector is in several regards still worth some attention.


The rise of deepwater E&P constituted a boon for the offshore fleet, helping to drive, for example, 180% and 60% increases in the FPSO and floater fleets from 2000 to 2015. However, deepwater development has lagged exploration, and so the offshore sector is fairly exposed to projects with high breakevens – problematic, given the oil price. But could the downturn actually help deepwater E&P in the long term?

Deepwater Exploration

The first deepwater offshore discovery was not made until 1976, by which point 1,018 shallow water fields had been discovered and 350 brought onstream, and it was only in the late-1990s that deepwater E&P really took off. Oil companies began pushing deeper into the US GoM, while the internationalization of the industry in the 2000s saw a spate of deepwater discoveries off West Africa and Brazil. A robust and rising oil price helped sustain rising deepwater E&P until 2015, with India, Australia and East Africa becoming important frontiers too. The average water depth of global offshore field discoveries passed 200m for the first time in 1996, 500m in 2004 and 800m in 2012, and the number of deepwater discoveries averaged 55 per year from 2005 to 2015.

Deepwater Production

However, as the main graph shows, the mean water depth of discoveries rose much faster than did that of start-ups: the former stood at 734m in 2015, the latter at 377m. Indeed, by 2016, out of a total of 998 deepwater finds, just 27% had started up, with deepwater start-ups averaging 19 per year from 2005 to 2015. The divergence was in large part because technological barriers and cost overheads in deepwater production – subsea, SURF and MOPU – are more complex and expensive than in exploration, and efficiency gains seem to have been more limited to date as well. Deepwater project sanctioning was therefore relatively inhibited, and due to limited sanctioning, the backlog of undeveloped deepwater fields grew at a faster rate than that of shallow water fields, as indicated by the inset graph. Thus over time, the overall backlog of potential projects has become more costly and complex. Indeed, some reports suggest oil project average breakevens have risen by c.270% since 2003.

Deepwater Challenges

This is partly why the offshore outlook is challenged at present: deepwater fields have relatively high breakevens (usually $60-$90/bbl) yet also form a major part of oil companies’ portfolios. Some major oil companies have indicated that 2016 E&P spending cuts are to bite deeper off than onshore, where costs are lower (even for shale, in many cases). In January 2016, Chevron decided to axe outright Buckskin, a US GoM project in a water depth of 1,816m with a breakeven of c.$72/bbl. ConocoPhilips, meanwhile, is planning to exit deepwater altogether.

However, in order to make deepwater viable again, many companies are trying instead to cut project costs. Statoil, for example, has reduced the CAPEX of Johan Castberg by 48% and the breakeven by 40%. Some cost savings (in day rates, for instance) are likely to be cyclical; others, such as in subsea fabrication, yielding improved deepwater project economics, are likely to be more lasting. So while exposure to deepwater projects is clearly a challenge given the current oil price, cost cutting now could be to the benefit of deepwater E&P in the long run.


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?

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.

Vietnam has the third largest proven oil reserves in the Asia Pacific region – but much of its existing offshore production is from declining shallow water fields. So the country’s first deepwater discovery, made in October, is a potentially exciting development. Could deepwater E&P activity in Vietnam be set to take off, or will weak oil prices and disputes over territorial waters prove problematic?

Shallow Beginnings

Most of Vietnam’s 0.28m bpd of offshore oil and 0.99bn cfd of offshore gas production is derived from fields in the Nam Con Son and Cuu Long basins, all of which are in less than 200m of water. The Cuu Long basin is perhaps the most successful area off Vietnam as it is home to many large fields, including Bach Ho, Su Tu Vang and Rang Dong. The dominance of shallow fields has skewed development towards fixed platforms. 88% of all active Vietnamese fields are exploited as such. Of these fields, the Bach Ho field accounts for 34 cor 37% of the total found on active fields.

Operators in Vietnam mainly consist of local and regional NOCs as well as IOCs (most commonly via joint operating companies in partnership with Petrovietnam). While significant market reforms have increased foreign investment in Vietnam’s offshore sector, further improvements to its transaction and tax systems could quicken the pace of foreign participation in the future.

Wading Into Deeper Waters

No significant shallow discoveries have been made recently, meaning that there is little to offset Vietnam’s depleting shallow water reserves. This highlights the need to break into deepwater frontiers, which could hold substantial levels of undiscovered hydrocarbons. The VGP-131-TB well, Vietnam’s first discovery in water depths >500m, was drilled in October 2015 by the Vietgazprom JOC, at depths of 1,600m in the Saigon basin. The ultra-deep find could provide momentum for Vietnam’s push into deepwater exploration. However, unlike China, which is able to independently bring deepwater fields like the Lingshui 17-2 online, Vietnam could still need to rely on foreign cooperation to jointly develop such finds in the short term.

Shaky Prospects

Vietnam’s hydrocarbon resources mainly lie in the South China Sea, with the most recent discovery at the southern end. The sea is an area of multiple disputed territorial claims by many countries, including China. This could impede any deep developments, if international partners were to view overlapping sovereignty claims to be an excessive business risk. Perhaps more importantly though, the post-downturn attitude of IOCs is one of cost-consciousness given lacklustre economic conditions. This could skew near-term interest towards safer EOR projects instead of unproven deeper water development in the South China Sea.

Since Vietnam’s historical track record is in shallow waters, even if further deepwater discoveries are forthcoming, then the chance of rapid deepwater developments in the South China Sea is probably going to take time. It is likely to need outside expertise, and the current energy markets may well not be conducive to this. That said, the discovery of Vietnam’s first deepwater field marks a new chapter in the country’s oil and gas story.


Plagued by constant blackouts and power shortages, Egypt appears to be facing its worst energy crisis in decades. However, following the historic discovery of the giant gas field Zohr offshore Egypt in August this year and revived interest from IOCs, it seems that the tables are set to turn. Indeed, after a period of gas production decline, Egypt’s energy outlook is getting increasingly bright.

Slide Down The Gas Pyramid

Until recently, Egypt’s gas production story had been one of growth: production climbed from 1.68 to 5.76 bn cfd between 2000-2009 and in 2003, it was sufficient to kick-start LNG exports. However, a combination of political unrest (notably the Arab Spring of 2011) and rising population has resulted in natural gas supply shortages over the last 5 years. Domestic gas demand has on average grown by 8% y-o-y, eventually outstripping supply. As a result, Egypt has been forced to re-route LNG destined for exports to domestic consumption. Indeed, at the start of 2014, BG announced it was breaking its contracts because it was unable to export enough gas. This year, Egypt resorted to importing LNG from Qatar – a bitter moment for the previous exporter.

Enter Zohr

They say that when you hit bottom, the only way is up and for Egypt, this seems to be the case. Earlier this year, ENI made what is believed to be the largest ever gas discovery in the Mediterranean, named Zohr. The field is part of the Levantine Basin, home to other prolific gas finds such as the Israeli Leviathan field. ENI puts the find down to different use of sequencing models, concentrating on carbonate rather than classical sand reservoirs. The gas giant (estimated to hold 30 tcf of lean gas) is located in water depths of 1,450m, providing an exciting departure from typical shallow exploration of mature basins in the region. Additionally, BP announced a $12 billion investment in Egypt’s West Nile Delta project: another deepwater discovery with 5 tcf of gas resources. A move to deeper waters creates opportunity for subsea development, the current production solution of choice in all of the country’s active deepwater fields. Out of the 68 active subsea units in Egypt, 40 are operated by ENI and 8 by BP. It is likely that these operators will continue to implement subsea development in their future projects.

Clash Of The Giants

Elsewhere, the discovery of Zohr was not such welcome news. There were plans to import gas via a pipeline from the Tamar field and (once in production) the competing gas giant, Leviathan, in Israel. Plans for the Leviathan field will now have to be redrawn and potentially accelerated if Israel wants a claim of the region’s LNG exports. However, following extensive regulatory and anti-trust objections, its start-up date remains uncertain.

Nevertheless, it is clear that Egypt’s fortunes are turning. The Zohr discovery, alongside other scheduled start-ups, will strengthen Egypt’s energy balance in the long-term. And the story does not end here: it has been reported that there are 7 other deepwater blocks with similar lithology to ENI’s. There is evidently a revived interest in the Levantine basin, as IOCs begin to wonder where the next giant could be hiding.


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.


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.


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.


Over the hill; past its peak; long in the tooth: like a worn-out old racehorse, the North Sea E&P sector is sometimes discussed in disparaging terms. In recent years however, it has been making something of a comeback, gaining ground when it comes to exploration and at least holding steady-ish when it comes to production. The question is, can this pace be sustained in the current oil price environment?

Saddling Up

The UK and Norway have long been the front-runners when it comes to offshore activity in the North Sea. In the 1970s, an average of 187 offshore wells were spudded per year in UK and Norwegian waters. As the graph shows, in the years 1970-76, more than 50% of these were exploration wells. Production was low (0.85m boepd in 1975), as few of the discoveries made since the first find in 1965 had been developed. But then in 1976, Brent started up, with Ekofisk following in 1977. During the course of bringing these and other large fields onstream, appraisal and development drilling raced ahead of exploration; from 1990, the number of exploration wells drilled each year began falling too. Field operators were now focusing on production over exploration. The two countries’ offshore production peaked in 2002 at 8.64m boepd from 337 fields. This year was also the nadir for exploration drilling: of 503 wells spudded, just 32 (6.4%) were exploration wells.

Second Wind

Oil companies therefore found total production falling just as reserves were being replaced at the slowest rate since North Sea exploration began. The more prudent then applied the spur to exploration once more, even as they tried to stop production decline using EOR. Exploration in the years 2003-14 in the central North Sea met with some notable successes, like the giant Johan Sverdrup discovery in 2010, with 2P reserves of 2.2bn bbl oil and 394bn cf gas. Operators also began venturing into the mostly unexplored Barents Sea and west of Shetlands waters. Hence, in 2014, 27% of wells spudded in UK or Norwegian waters were for exploration, a share similar to the late 1980s. Production, meanwhile, fell by only 0.8% y-o-y, versus the average y-o-y decline over 2002-14 of 3.9%.

The Final Furlong?

The area’s offshore sector was thus moving at a relatively good pace. However, 2014 exploration campaigns and most incipient development projects were conceived in a more robust oil price environment than the present: E&P economics in frontier areas like the Barents Sea are highly uncertain while the oil price is less than $80/bbl. Perhaps then, with oil company spending cuts, the recovery in exploration will be stopped in its tracks and production decline may resume. On the other hand, some smaller operators are taking advantage of low rig and OSV day rates to increase exploration. Falling EPC costs could also help to reduce development project breakevens, flogging North Sea E&P onwards once more. And if the oil price were to return to $100/bbl+, then there is the potential for further upside.

So there you have it. The weaker oil price has made some oil companies pull on the reins, but there is still potential for the second burst of North Sea E&P activity to run on, in the right conditions. The area may no longer be the fiery colt of offshore E&P, but it probably has some way to run yet before being put out to pasture.


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.