Deflation, Shell, and Bourbon…

Shell gave a strategy update this week (the graphic above is from the presentation). More of the same really if you read this blog: more investment in shale and targeted and steady investment in offshore:

Shell 2025 outlook.png

And you can see the effect that over time Deep Water will be an increasingly smaller (but still important) part of production at Shell:

Shell 2025 Investment Tilt.png

But there is a clear tilt to shale and power. Yes they are spending more but the supply chain aren’t getting it:

Shell cost reduction to 2025.png

Shell Vendor Spend.png

For the offshore supply chain this is a very different world because a large number of the assets were acquired when that 2015 number was sloshing around the industry along with all the other money. Boats and rigs were ordered with 2015 dollars in mind and those days are long gone.

This is an age of deflation. Oil companies can, and have, sustainably changed the cost of production and met long-term demand expectations. The last offshore asset price bubble required both a demand boom and a credit boom. The demand boom has clearly gone and instead of the credit boom were are starting to see a credit contraction in a meaningful sense.

Slowly banks are realising that when the industry declines this much they don’t own and asset (loan), all they really own is a claim to the economic value an asset can produce. For all offshore assets that is much lower now than it was in 2015, and therefore those assets are not going to pay back anything like all the money they owe in an accounting sense. Slowly some banks stop rolling over credit, as has happened with DOF and Solstad among other firms, and the liquidity really starts to dry up.

The smaller banks are trying to force the larger banks to buy them out of these positions. This is clearly what is happening at DOF and Solstad. The larger banks in these deals will have to double down or accept large write-offs. In addition the number of hedge funds and other who have lost money on asset recovery plays is now so large that selling these deals is all but impossible (see Seadrill). Easy to get into but very hard to get out.

Bourbon creditors appear to have realised this.  A restructuring proposal has been sent to the Board for consideration. In reality the default is so large the creditors own the company. The creditors will write down billions of debt, Bourbon will reappear as a new financial entity, looking operationally a lot like the old, but like everyone else in the market believing their assets must be worth at least what they restructured them at. Capacity will be kept high and competition will ensure rates continue at below economic levels. It is a parable of the whole industry at the moment which shows no sign of abatement. Watching with interest DOF and Solstad because the larger Nordic banks stand to lose some real money here and yet the investment required to go on pretending would seem untouchable to any serious investor without write-offs in the billions of NOK from the banks. As offshore supply leads so will the rig companies as the head for their second round of restructurings (who inexplicably still seem to have access to bank financing).

But this is crazy world we live in. Much like the dotcom boom people are going to ask one day how they ever put money into a shipping company that excluded the cost of running a ship from it’s reported numbers:

  1. Positive EBITDA (adj.) of USD 617 thousands, excluding start-up cost, dry dock, special survey and maintenance (Q1 18 USD 400 thousands) from chartering out the 5 large –sized PSV’s. Including the ownership in Northern Supply AS (25.53%) the group netted a positive EBITDA (adj.) excluding start-up cost, dry dock, special survey and maintenance of USD 518 thousands (Q1 18 USD 200 thousands).

This isn’t going to happen quickly. Credit effects take significantly longer to work through than demand side effects. Once these banks have written off loans in a meaningful sense getting them to lend against these assets again will be nearly impossible.

And yet the cost pressure will continue:

Shell Cost pressure.png

Unconventional verus offshore demand at the margin…

Economic growth occurs whenever people take resources and rearrange them in ways that are more valuable. A useful metaphor for production in an economy comes from the kitchen. To create valuable final products, we mix inexpensive ingredients together according to a recipe. The cooking one can do is limited by the supply of ingredients, and most cooking in the economy produces undesirable side effects. If economic growth could be achieved only by doing more and more of the same kind of cooking, we would eventually run out of raw materials and suffer from unacceptable levels of pollution and nuisance. Human history teaches us, however, that economic growth springs from better recipes, not just from more cooking. New recipes generally produce fewer unpleasant side effects and generate more economic value per unit of raw material…

Every generation has perceived the limits to growth that finite resources and undesirable side effects would pose if no new recipes or ideas were discovered. And every generation has underestimated the potential for finding new recipes and ideas. We consistently fail to grasp how many ideas remain to be discovered. The difficulty is the same one we have with compounding. Possibilities do not add up. They multiply.

Paul Romer (Nobel Prize winner in Economics 2018)

Good article in the $FT today on Shell’s attitude to US shale production:

Growing oil and gas production from shale fields will act as a “balance” for deepwater projects, the new head of Royal Dutch Shell’s US business said, as the energy major strives for flexibility in the transition to cleaner fuels. Gretchen Watkins said drilling far beneath oceans in the US Gulf of Mexico, Brazil and Nigeria secured revenues for the longer-term, but tapping shale reserves in the US, Canada and Argentina enabled nimble decision-making.

“The role that [the shale business] plays in Shell’s portfolio is one of being a good balance for deepwater,” Ms Watkins said in her first interview since she joined the Anglo-Dutch major in May…

Shell is allocating between $2bn and $3bn every year to the shale business, which is about 10 per cent of the company’s annual capital expenditure until 2020 and half of its expected spending on deepwater projects. [Emphasis added].

Notice the importance of investing in the energy transition as well. For oil companies this is important and not merely rhetoric. Recycling cash generated from higher margin oil into products that will ensure the survival of the firm longer term even if at a lower return level is currently in vogue for large E&P companies. 5 years ago a large proportion of that shale budget would have gone to offshore, and 100% of the energy transition budget would have gone to upstream.

The graph at the top from Wood MacKenzie is an illustration of this and the corollary to the declining offshore rig numbers I mentioned here. Offshore is an industry in the middle of a period of huge structural change as it’s core users open up a vast new production frontier unimaginable only a short period before. The only certainty associated with this is lower structural profits for the industry than existed ex ante.

Note also the split that the – are making between high CapEx deepwater projects and shale. Shell’s deal yesterday with Noreco was a classic case of getting out of a sizable business squarely in the middle of these: capital-intensive and not scalable (but still a great business). PE style companies will run these assets for cash and seem less concerned about the decom liabilities.

You can also see this play out in terms of generating future supply and the importance of unconventional in this waterfall:

Shale production growth

As you can see from the graph above even under best case assumptions shale is set to take around 45% of new production growth. When the majority of the offshore fleet was being built if you had drawn a graph like this people would have thought you were mad – and you would have been – it just highlights the enormous increase in productivity in shale. All this adds up to a lack of demand momentum for more marginal offshore projects. The E&P companies that are investing, like Noreco, have less scale and resources and a higher cost of capital which will flow through the supply chain in terms of higher margin requirements to get investment approval. This means a smaller quantity of approved projects as higher return requirements means a smaller number of possible projects.

Don’t believe the scare stories about reserves! The market has a way of adjusting (although I am not arguing it is a perfect mechanism!):

Running Out of Oil.png

A brave new world…

“One believes things because one has been conditioned to believe them.”
Aldous Huxley, Brave New World

Yet a rebound in prices, ineluctable as it may be, will not turn back the clock on the oil market. Nor will it mark a return to the status quo ante. The market that emerges from the current process of rebalancing will differ from the one that preceded it. The idea of a pendulum swing in oil markets is unexceptional; such swings have occurred in previous episodes of price correction. But this swing is different. When the dust settles, the market will have shifted, perhaps beyond recognition. The process of adjustment and restructuring ushered in by the price collapse marks the beginning of a new era in the history of oil and energy markets that will present both opportunities and daunting challenges for the industry.

What makes the current selloff and coming recovery different from previous market cycles is the advent of U.S. shale oil. The shale revolution has transformed oil market dynamics. It triggered the oil price collapse. It is now shaping the course of the recovery. It will eventually define the features of the energy landscape that will in due course emerge from the downturn. [Emphasis added].

January 19, 2016, Congressional Testimony of Antoine Halff, Senior Research Scholar and Director of the Global Oil Market Program, Center on Global Energy Policy, Columbia University School of International and Public Affairs

Before the Committee on Energy and Natural Resources, United States Senate

I came across the above article today. It is remarkably prescient about the changes that would occur in 2016/17, although far too cautious about the ability of the US to create another production basin on the scale of Iran in the Permian. Halff talks of a “two speed industry”:

Last but not least, the advent of the shale oil industry has been challenging the very business model of the oil industry. Oil companies have traditionally been large, deep-pocketed and professionally conservative, and have usually operated under a price umbrella of one kind or another: Rockefeller’s Standard Oil, the Seven Sisters, OPEC. Shale oil companies – small, nimble, highly leveraged, intensely adaptable – break that mold. Whereas conventional oil production requires large upfront investment and lead times measured in years if not decades, the shale business cycle is shorter: upfront shale costs are relatively low; decline rates are steep; lead times and payback times are measured in months rather than years.

Which is the Spencer Dale argument I use here often. The economists appear to have this seismic shift well understood. There is a great article by John Kemp on Reuters (where the featured graph came from) noting:

Benchmark Brent prices have already risen by more than $45 per barrel or 170 percent from their cyclical trough in early 2016.

Front-month futures prices, at almost $75 per barrel, are now trading close to the inflation-adjusted average for the last price cycle, which started in 1998 and finished in 2016.

So far this year, futures prices have averaged nearly $68 per barrel, which is well above the post-1973 real average price of $50-$55.

Futures prices have shifted from a big contango during the slump into an increasingly wide backwardation since the middle of 2017, which is consistent with a shift from over-supply to under-supply.

Both commentators above see the rising price as risking nothing more than a boom in shale spending. And in a way we are in a mini-boom. When the price of a commodity rises 170% in 24 months it is normally viewed as a recovery. The spot price of oil might go higher…  For a supply chain long on capacity and supply it just doesn’t feel like it…

In that vein Shell released their Q1 results yesterday. What everyone in offshore was hoping the Shell CEO would say was this:

“Shell released excellent numbers with a rising oil price today. To that end I have instructed the upstream department to immediately commission as many offshore projects as possible. Rigs, jack-ups, boats, there will not be enough by the time I have finished signing purchase orders for major projects. If you thought 2013 was busy wait until the Shell Board has finished approving projects”…

Of course what the CEO actually said was this:

“We have a strong financial framework. Our commitment to capital discipline is unchanged, we are making good progress with our $30 billion divestment programme and our outlook for free cash flow – which covered our cash dividend and interest this quarter and over the last year – is consistent with our intent to buy back at least $25 billion of our shares over the period 2018-2020.”

As I said yesterday this is a different world from 2013. Shell shares actually dropped on the news despite the fact they are making higher profits than on $100 oil. And the hangover from the 2014 downturn is still there for E&P companies because Shell paid dividends with shares recently to cut the cash cost, the commitment to reduce the number of shares on issue is just the slowburn effect of the downturn that reduces cash available for projects.

And Shell make it very clear that for the next three years if Deepwater spending comes in at the low end of forecasts, and Shale and New energies come it at the high end, then both will be worth ~$5bn (only $1bn seperate them at the top end):

Shell Q 1 2018 CAPEX

Shell doesn’t appear to be markedly different from any other large E&P company: Total had a very similar theme yesterday as well. Secular change brings a brave new world…

 

Diverging results point to the future of offshore… procyclicality reverses…

Colin, for example, has recently persuaded himself that the propensity to consume in terms of money is constant at all phases of the credit cycle.  He works out a figure for it and proposes to predict by using the result, regardless of the fact that his own investigations clearly show that it is not constant, in addition to the strong a priori reasons for regarding it as most unlikely that it can be so.

The point needs emphasising because the art of thinking in terms of models is a difficult–largely because it is an unaccustomed–practice. The pseudo-analogy with the physical sciences leads directly counter to the habit of mind which is most important for an economist proper to acquire…

One has to be constantly on guard against treating the material as constant and homogeneous in the same way that the material of the other sciences, in spite of its complexity, is constant and homogeneous. It is as though the fall of the apple to the ground depended on the apple’s motives, on whether it is worth while falling to the ground, and whether the ground wanted the apple to fall, and on mistaken calculations on the part of the apple as to how far it was from the centre of the earth.

Keynes to Harrod, 1938

 

A, having one hundred pounds stock in trade, though pretty much in debt, gives it out to be worth three hundred pounds, on account of many privileges and advantages to which he is entitled. B, relying on A’s great wisdom and integrity, sues to be admitted partner on those terms, and accordingly buys three hundred pounds into the partnership.The trade being afterwords given out or discovered to be very improving, C comes in at fivehundred pounds; and afterwards D, at one thousand one hundred pounds. And the capital is then completed to two thousand pounds. If the partnership had gone no further than A and B, then A had got and B had lost one hundred pounds. If it had stopped at C, then A had got and C had lost two hundred pounds; and B had been where he was before: but D also coming in, A gains four hundred pounds, and B two hundred pounds; and C neither gains nor loses: but D loses six hundred pounds. Indeed, if A could show that the said capital was intrinsicallyworth four thousand and four hundred pounds, there would be no harm done to D; and B and C would have been obliged to him. But if the capital at first was worth but one hundred pounds, and increasedonly by subsequent partnership, it must then be acknowl-edged that B and C have been imposed on in their turns, and that unfortunate thoughtless D paid the piper.
A Adamson (1787) A History of Commerce (referring to the South Sea Bubble)

The Bank of England has defined procyclicality as follows:

  • First, in the short term, as the tendency to invest in a way that exacerbates market movements and contributes to asset price volatility, which can in turn contribute to asset price feedback loops. Asset price volatility has the potential to affect participants across financial markets, as well as to have longer-term macroeconomic effects; and
  • Second, in the medium term, as a tendency to invest in line with asset price and economic cycles, so that willingness to bear risk diminishes in periods of stress and increases in upturns.

Everyone is offshore recognises these traits: as the oil price rose and E&P companies started reporting record results offshore contractors had record profits. Contractors and E&P comapnies both began an investment boom, highly correlated, and on the back of this banks extended vast quantities of credit to both parties, when even the banks started getting nervous the high-yield market willingly obliged with even more credit to offshore contractors. And then the price of oil crashed an a dramatically different investment environment began.

What is procyclical on the way up with a debt boom always falls harder on the way down as a countercyclical reaction, and now the E&P companies are used to a capital light approach this is the new norm for offshore. The problem in macroeconomic terms, as I constantly repeat here, is that debt is an obligation fixed in constant numbers and as the second point above makes clear that in periods of stress for offshore contracting, such as now, the willingness to bear risk is low. Contractors with high leverage levels that required the industry to be substantially bigger cannot survive financially with new lower demand levels.

I mention this because the end of the asset bubble has truly been marked this week by the diverging results between the E&P companies and some of the large contractors. All the supermajors are now clearly a viable entities at USD 50 a barrel whereas the same cannot be said for offshore rig and vessel contractors who still face large over capacity issues.

This chart from Saipem nicely highlights the problem the offshore industry has:

Saipem backlog H1 2017 €mn

Saipem backlog Hi 2017.png

Not only has backlog in offshore Engineering and Construction dropped 13% but Saipem are working through it pretty quickly with new business at c.66% of revenues. The implication clearly being that there is a business here just 1/3 smaller than the current one. You can see why Subsea 7 worked so hard to buy the EMAS Chiyoda backlog because they added only $141m organically in Q2 with almost no new deepwater projects announced in the quarter.

It is not that industry conditions are “challenging” but clearly the industry is undergoing a secular shift to being a much smaller part of the investment profile for E&P companies and therefore a much smaller industry as the market is permanently contracting as this profile of Shell capex shows:

Shell Capex 2017

A billion here, a billion there, and pretty soon you are talking real money. The FT had a good article this week that highlighted how “Big Oil” are adapating to lower costs, and its all bad for the offshore supply chain:

The first six months of this year saw 15 large conventional upstream oil and gas projects given the green light, with reserves of about 8bn barrels of oil and oil equivalent, according to WoodMac. This compared with 12 projects approved in the whole of 2016, containing about 8.8bn barrels. However, activity remains far below the average 40 new developments approved annually between 2007 and 2013 and, with crude prices yo-yoing around $50 per barrel, analysts say the economics of conventional projects remain precarious.

Not all of these are offshore but the offshore supply chain built capacity for this demand and in fact more because utilisation was already slipping in 2014. And this statistic should terrify the offshore industry:

WoodMac says that half of all greenfield conventional projects awaiting a green light would not achieve a 15 per cent return on investment at long-term oil prices of $60 per barrel, raising “serious doubt” over their prospects for development. By this measure, there is twice as much undeveloped US shale oil capable of making money at $60 per barrel than there is conventional resources.

The backlog (or lack of) is the most worrying aspect for the financing of the whole industry. E&P companies have laid off so many engineers and slowed down so many FIDs that even if the price of oil jumped to $100 tomorrow (and no one believes that) it would take years to ramp up project delivery capacity anyway. Saipem and Subsea 7 are not exceptions they are large companies that highlight likely future work indicates that asset values at current levels may not be an anamoly for vessel and rig owners but the “new normal” as part of “lower for longer”.

I recently spoke to a senior E&P financier in Houston who is convinced “the man from Oaklahoma” is right but only because he thinks overcapacity will keep prices low: c. 50% of fracing costs come from sand, which isn’t subject to productivity improvements, and he is picking that low prices eventually catch up with the prices being paid for land. I still think that the more large E&P companies focus on improving efficiency will ensure this remains a robust source of production given their productivity improvements as Chevron’s results showed:

Chevron Permian Productivity 2017

Large oil came to the North Sea and turned it into a leading technical development centre for the rest of the world. Brazil would not be possible without the skills and competencies (e.g. HPHT) developed by the supermajors in the North Sea and I think once these same companies start focusing their R&D efforts on shale productivity will continue to increase and this will be at the expense of offshore.

It is now very clear that the supermajors, who count for the majority of complex deepwater developments that are the users of high-end vessel capacity, are very comfortable with current economic conditions. They have no incentive to binge on CapEx because even if prices go up rapidly that just means they can pay for it with current cash flow.

That means the ‘Demand Fairy’ isn’t saving anyone here and that asset values are probably a fair reflection of their economic earning potential. Now the process between banks and offshore contractors has become one of counter-cyclicality where the asset price-feedback loop is working in reverse: banks will not lend on offshore assets because no one knows (or wants to believe) the current values and therefore there are no transactions beyond absolute distress sales. This model has been well understood by economists modelling contracting credit and asset values:

Asset Prices and Credit Contracttion

Getting banks to allocate capital to offshore in the future will be very hard given the risk models used and historical losses. Offshore assets will clearly be subject to the self referencing model above.

I remain convinced that European banks and investors are doing a poor job compared to US investors about accepting the scale of their loss and the need for the industry to have significantly less capital and asset value than it does now. Too many investors thought this downturn was like 2007/08, when there was a quick rebound, and while this smoothed asset prices somewhat on the way down this cash was used mainly for liquidity, it is now running dry and not more will be available (e.e. Nor Offshore) at anything other than penal terms given the uncertainty. Until backlog is meaningfully added across the industry asset values should, in a rational world, remain extremely depressed and I believe they will.

Shell and Bourbon: a tale of two cities

“In short,” said Sydney, “this is a desperate time, when desperate games are played for desperate stakes.” 

A Tale of Two Cities

Despite oil prices remaining above US$50 a barrel during the 1st quarter of 2017, activity is yet to recover in the Shallow water offshore and Deepwater offshore sectors”

Jacques de Chateauvieux, Chairman and Chief Executive Officer of BOURBON Corporation.

I am absolutely not going to turn this blog into one that goes through the financial results every quarter (and even less so one that follows the oil price), but I do think now is an interesting time because on a volume basis they make up a large percentage of the total offshore CapEx so their spending plans are important. The most important forward number the contracting community needs to focus on is backlog, for the simple reason that in volume terms it drives the number of days utilisation. Shell reported today as did Bourbon, and I believe that they support the view I have taken here and here with BP: we are looking at a structural change in the offshore contracting industry and the likelihood of a supply crunch saviour is unlikely at best.

The massive supply crunch that the IEA forecasts doesn’t appear to be showing up in the physical market (with oil down nearly 5% today although I believe daily prices are a close to a random variable) or the futures market. This IEA forecast is starting to look chimerical:

Global oil supply may struggle to match demand after 2020, when the pinch of a two-year decline in investment in new production could leave spare capacity at a 14-year low and send prices sharply higher, the International Energy Agency said on Monday.

Investors generally are not betting on a sharp rise in the price of crude oil any time soon, but the contraction in global spending in 2015 and 2016 and growing global demand means the world could well face a “supply crunch” if new projects are not soon given the go-ahead, the IEA said in its five-year “Oil 2017” market analysis and forecast report

Firstly the Shell numbers: unsurprisingly there was a massive growth in profit as the oil price went straight to the bootom line. Like BP its all about the CapEx and the dividends:

Shell Dividends

Despite a massive drop in earnings Shell sells stuff and borrows more to pay shareholders the same. And like BP it will massively cut back CapEx compared to historic periods:

Shell Capex.png

The cut from 2013 to 2016 is nigh on 50% for upstream, It is also worth looking at the drop in Europe. Yes, Shell sold a large proportion of the portfolio to Chryosoar, but from a market perspective it will take the new company some time to develop and execute its plans, and there is more chance than not that they take more time to develop as a new management team and shareholder base come to grips with the scale of what they have purchased and match their asset to their strategic plans. Some quick wins maybe, huge CapEx developments… Unlikely. For European contractors that is bad news.

Shell also made plain in their strategy presentation last year that:

Capital investment will be in the range of $25-$30 billion each year to 2020, as we improve capital efficiency and ensure a more predictable development funnel for new projects. Investment for 2016 is expected to be $29 billion, excluding the purchase price of BG, some 35% lower than the pro-forma Shell-plus-BG level in 2014. In the prevailing low oil price environment we will continue to drive capital spending down towards the bottom end of this range; or even lower if needed. In a higher oil price future we intend to cap our spending at the top end of the range.

As I said I believe their shareholders have made clear the dividend is sacrosanct and the management get it. This is what economists call a time consistency issue, and in this case the incentive to keep the commitment is the same as the incentive to make the commitment. In other words, they are likely to keep this promise because everyone is incentivised just to take the money if oil prices suddenly shoot up.

Shell also noted geographically their commitment to deepwater:

Brazil and the Gulf of Mexico represent the best real estate in global deep water. We are developing competitive projects here based on this advantaged acreage. Shell’s deep-water production could double, to some 900 thousand barrels of oil equivalent per day (kboed) in 2020, compared with 450 kboed in 2015.

The fact is that operating costs are lower in these regions compared to the North Sea: e.g. PSV runs have lower spec vessels, cheaper fuel, cheaper crews, and lower CapEx. It’s all about driving unit production costs down now, just like a manufacturing business every process will be examined and reviewed and an attempt made to lower the cost.

To that end Shell have approved the Kaiskias development for a 40 000 bpd field (them picture here). Like BP on Mad Dog Phase 2 Shell got a near 50% reduction in development costs and replicated previous design knowledge. These companies are using large offshore projects as the baseload for their production needs and building shale capability as the marginal production that flexs as market needs dictate.

And shale is flexible:  the Baker Hughes rig count hit 697 rigs last week, up 9 on the last week, but up an astonishing 365 year-on-year (91%). It’s just the right growth rate, not so high cost goes mad, but high enough to substantially affect the market price and keep investment incoming. Goldilocks growth. Right now those rig and service companies are adding more capacity, training more people, learning how they can extract more per well, and lower the running cost. Every day they learn more and apply more in a self referential cycle that is the hallmark of standardisation and lowering unit costs. Bet against it at your peril.

The other side of this production revolution could been seen as Bourbon also reported today. Revenue down 28% year-on-year! Bourbon is so big it is a bellweather for those exposed to assets without the project execution capability that others have. The contrast with Shell couldn’t be more obvious. Poor utilisation and management highlighting only they had negotiated with ICBC to taper lease payments. There is no light at the moment for subsea – which is consistent with what GE said this week. The common theme here is that subsea is structurally unattractive compared to other development opportunities. High upfront exploration and appraisal costs relative to flow rates make it harder to attract upfront funding and capacity utilisation at below economic levels for vessel operators still not lowering costs enough to bring the market into equilibrium.

You don’t need to run a regression to understand what is happening here: investment is pouring into shale and ignoring offshore for all but the most certain bets. Until CapEx from the E&P companies comes back any hope of a “recovery” for those long on tonnage is a mirage. CapEx drives utilisation in a way IRM just cannot. At some point the offshore community is going to have to stop pretending the only possible solution here is a market “recovery”. There has been a fundamental and structural change in the market. Multi-year commitment to low CapEx is not what the global fleet was built for, it was built for 2013 when Shell Upstream alone chucked a cheeky USD 24bn at improving production, not a measly USD 12bn per annum capped.

I think this highlights what a massive mistake Solstad has made here by taking on Farstad and DeepSea. A supplier of high-end CSVs may have had an independent future, but exposing yourself to commodity tonnage, predominantly in structurally unattractive regions suffering declining investment, without enough scale to generate pricing power, is looking more and more like a poor move every day (not that it ever looked good). Minorities in Solstad must be livid.

Clearly those contractors who can deliver large offshore projects in deepwater have a viable business model if they don’t have too much tonnage. For the rest it will be years of sub-economic returns unless restructuring brings a new capital structure.