Archives for posts with tag: deepwater

The expansion of European settlement in North America – the pushing westwards of the frontier – has come to be seen as a defining part of American culture, spawning a whole genre of films and books set in the historical “Wild West”. That same pioneering spirit seems to be alive still today, at least in the US Gulf of Mexico (GoM), where 49 ultra-deepwater field discoveries have been made in the last decade.

Once Upon A Time In The Gulf

Offshore E&P in the US GoM began in the 1930s, picking up pace in the 1950s. By the end of 1975, a total of 444 shallow water fields had been discovered in the area and 256 of these had been brought into production. Gas fields predominated, accounting for 75% of discoveries and 31% of start-ups. Early E&P in the area made extensive use of jack-up drilling rigs and lift-boats. Fixed platforms were the favoured development method, with 86% of the 256 start-ups using fixed platforms. Thus were the first pioneering steps taken in exploiting the US GoM.

For A Few Dollars More

However, compelled by the need to find new reserves, oil companies active in the US GoM began pushing outwards, into deeper waters: the first deepwater discovery in the area was made in 1976. The frontier has now moved quite a way onwards since those early days. The average distance to shore of the 129 offshore discoveries in the area since start 2007 is 145km, while 72% (93) of these fields are in water depths of 500m or greater. The focus has also shifted from gas to oil: 58% of the 129 finds were oil fields, including 81% of the 93 deepwater finds. The US GoM has been dubbed one corner of the “Golden Triangle” of deepwater E&P and (supported by high oil prices until 2015) it has accounted for 16% and 19% of deepwater and ultra-deepwater finds globally since 2007. As shown by the graph, this was in spite of a slowdown in the wake of Deepwater Horizon. Floater utilisation dipped to 80% in 2011 but recovered, and a peak of 54 active floaters in the area was reached in January 2015 (26% of the active fleet).

Manifest Destiny?

So US GoM exploration was a major beneficiary of a high oil price. But how might it fare in a potential “lower for longer” price scenario? The outlook for jack-ups is bleak, with utilisation in the area standing at 24% as of December 2016. Simply put, the shallow water GoM is gas prone, and gas fields in the area are generally not competitive with onshore shale gas. At the US GoM (ultra-)deepwater frontier though, things do not look quite as bad as might be expected. On the one hand, over the last two years, floater utilisation has gradually fallen to 70%, as owners have struggled with rig oversupply, and dayrates are severely pressurised. On the other hand, there have been large finds made since 2014, such as Anchor and Power Nap, and wells are underway or planned for potentially major prospects such as Dawn Marie, Warrior, Castle Valley, Hershey, Hendrix, Sphinx and Dover. Many oil companies see the US GoM as a core area, and are prepared to invest to bolster oil reserves, even via drilling of, for example, costly HPHT reservoirs in the Lower Tertiary Wilcox formation.

As in the Wild West, at times things can be tough at offshore frontiers. Rig owners (and others) are experiencing this in the US GoM. But with some oil companies taking a long-term view, the pioneering spirit may not have been snuffed out yet.

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As the many Greek players in the shipping industry know well, the legend of Icarus tells us the dangers of flying too high. Merchant vessel earnings eventually found their 2008 heights just as unsustainable, even as some talked of a “new paradigm”. Most will be familiar with the lengthy downturn that has followed. But spare a thought for the offshore markets, now going through their own Icarus moment.

Flying On The Dragon’s Back

As with the expectations of some in the shipping industry that Chinese demand for raw materials would grow indefinitely, the consensus over the 2010-13 period was that oil prices were set to remain above $100/bbl. Oil demand growth seemed firm and supply growth scarce as decline in output from ageing onshore fields undermined growth from new deepwater offshore regions. The offshore sector attracted interest from shipyards in both Korea and China, and amongst traditional shipowners (including some Greek players).

The precipitous fall from grace of the main shipping markets in late 2008 seemed to presage a tough and lengthy downturn. As the graph shows, the ClarkSea Index (an indicator of merchant sector vessel earnings) fell by more than 80% in a matter of weeks, and offshore support vessel (OSV) and rig dayrate indices fell by 50%. Yet, by late 2009, the oil price had bounced back, and offshore units seemed like attractive investment opportunities for diversification away from over-supplied shipping sectors.

On The Right Path?

For some years, offshore investors seemed to have taken the correct turning, as dayrates for rigs and OSVs soared, and by 2013 were close to the heights reached prior to the financial crisis. Meanwhile, the ClarkSea Index remained earthbound, with earnings hampered by a sluggish world economy and phases of newbuilding activity, as government stimulus and low newbuilding prices combined to boost counter-cyclical orders.

For Icarus, the heat of the sun proved to be his undoing. In the case of the offshore markets, the heights they reached were dashed by an unexpected underground source of oil and gas. Few saw coming the game-changing effect that technological change would have on the oil supply-demand balance. Fracking produced 3.8m bpd of additional onshore oil supply from US shale by 2015.

Initially, the effect of this extra supply was hidden, by outages due to political instability in areas such as Libya, Russia, and Iraq. But as oversupply of about 2m bpd became clearer, Saudi Arabia refused to resolve the problem through a unilateral oil output cut.

Down To Earth

Today the offshore markets look to be in an equally or even more challenged position than the major shipping segments. Dayrates for both rigs and OSVs have fallen by 40-50% over the course of the last eighteen months. There is currently little positive sentiment, and many assume that the near future for these offshore sectors could come to resemble the ClarkSea Index’s recent past. But cyclicality, after all, has been a part of these industries for decades. As the best Greek asset players will tell you, the key is to ride a market upturn, but to get out before you get too close to the sun.

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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.

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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.

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OIMT03Since the country’s oil reserves were nationalised by Lázaro Cárdenas in 1938, the state ownership of Mexico’s oil production has been an issue of totemic pride for Mexicans. For years, the bounty provided by the Cantarell project minimised the need to think about other options. But as the decline of ageing Bay of Campeche fields accelerates, increasing investment has been needed by Pemex both to shore up existing fields and also to appraise future areas of production.

Exploring Investment Expansion

The Graph of the Month shows the extent of the growth in Pemex’s Exploration and Production budget, as greater focus has come on developing new areas of oil production, some involving deeper waters or more complex development types than the fixed platforms found on Cantarell or Ku-Maloob-Zaap. Pemex’s E&P budget in 2013 was around 74% greater than five years earlier, and its projection for total expenditure is for further growth in its CAPEX budget through to 2018 at a rate of 3.8% per annum. Although this forecast is at an aggregate level, including all business units, the line on the graph shows the level of E&P spending that this implies given the share which the latter has been in recent history.

A Landmark Policy Change

On December 23rd, in the face of not-inconsiderable political opposition, the Mexican president signed a constitutional reform which, will end the 75-year old state monopoly on Mexican production, and allow private investment in Mexican developments. This could add to Pemex’s already substantial $149bn five-year investment plan.

Supporting Structures

This is, of course, all positive news to owners of offshore structures, raising the potential for greater future demand for structures off Mexico. Mexico is already beginning to generate demand for increasing numbers of rigs and OSVs. A number of Mexico-based companies have attracted investment from US and Asian sources of finance looking to gain exposure to the Mexican market (notably the expected need for additional high-specification jack-ups: at least 18% of the current orderbook is for deployment there).

As well as continued work to shore up output on the major fields, plans for new fields are underway. These include the FPSO development on the Ayatsil heavy oil field (targeting 2016 start-up) and Lakach, Pemex’s first deepwater project (2015). This field has been followed by several other finds in the Catemaco fold belt off Veracruz, results of the recent step-up in exploration by Pemex. Hub development may be possible, although falling American gas prices could be an issue. Looking further to the future, potential further deepwater activity could include a SPAR in the Perdido fold belt near US waters.

So, the future for investment offshore Mexico looks relatively bright, with optimistic projections for the levels of state investment. The lack of local experience in deep or more complex fields could be an issue, but as private investment and more third-party offshore contractors get involved, these challenges may be solved. All together, this makes Mexico an attractive prospect, as the drive towards new production stimulates additional demand for offshore units.