Productivity and capital reduction in offshore …

“Bank executives, believers in sound money to a man when other sectors of the economy were in trouble, became less keen on monetary purity when it came to their own survival…”

Philip Coggan, Paper Promises

From the $FT on Monday:

This has helped boost UK oil and gas output from 1.42m barrels of oil equivalent per day in 2014 to 1.63m boepd in 2017, a 14.8 per cent increase…
But the industry has now managed to lower costs from an average of £19.40 a barrel in 2014 to an estimated £11.80 a barrel this year, according to the UK Oil and Gas Authority, while total expenditure on investment and exploration has fallen from £15bn to £5bn over the same period.

Let’s be clear about what this sort E&P company productivity means in terms of market and price deflation for the offshore supply chain over a four year period: OpEx -39% and CapEx down 66%%! £10bn has been taken from a market of £15bn in revenue terms for the supply chain supporting “investment and exploration”! It is an extraordinary number for an industry supported by a large amount of leverage in the supply chain and represents a fundamental structural shift.

Yes the CapEx number is variable by year, and Clair Ridge and other fields had massive expenditure last year, but this is the future of offshore in the UKCS. The gross figure is probably a good proportionate proxy for all those in market, with the most oversupplied segments perhaps taking a bigger hit, but if you are a UK focused business this is the scale of the reduction in the market. And this in an environment when the oil price rose 44%! As anyone close to the E&P companies will tell you cost pressure is still relentless. A near 13% decline in the price of Brent over the last few weeks only adding to CFO determination to keep OpEx in check.

If you take Bob Dudley’s assertion that you get 40% more volume for your value offshore the market is at £7bn in 2010 terms i.e. more than a 50% decline and a smaller installed base in the future to maintain. The sanctioning of Tolmount yesterday was good news but it doesn’t change the macro statistics: this is a rapidly shrinking basin in market expenditure terms. There is simply no linear relationship between the oil price and the demand for offshore services in  the North Sea now.

There is a reason the Vard 801 has not been taken out by Technip or Subsea 7 and that is clearly in this environment the UKCS is a very difficult place to make money.  It is not sensible to invest in fixed assets for a market facing such steep declines in size. For UK focused contractors there is simply no way to remove that volume of revenue from the market and under any realistic assumptions and expect the same number of firms to survive or profitability levels to return to past averages. The industry must contract to reflect this but the high perceived asset values of the vessels and rigs have slowed this contraction.

If you took on debt in the good times your market has shrunk rapidly but your creditors expect to be paid back from a market that was in percentage terms vastly bigger. If you don’t think offshore has any hot air left to come out then take a look at the accounts of Nordic American Offshore: a North Sea PSV ‘pure play’.

NAO in 2017 (or materially in any other year) decided not to impair the value of their PSVs because they think they will earn their value back. NAO has 10 PSVs, debt of $~140m, ~$12 in cash, and having largely spent the $47.5m raised in 2017. In 2017 it spent ~$22.5m in costs to get ~$18m in revenue and it made another loss (obviously) for H2 2018, resorting to sending non laid-up PSVs to Africa to work. There is no realistic future for this company as a standalone enterprise and no industrial logic for this company to exist at current market demand levels. The vessels are worth less than the bank debt and their market is in a steep contraction. These PSVs are on the books at over £30m each!!! Sooner or later the facts of this market contraction with their cash position will collide.

There is simply no place for these supply companies with 10-20 vessels. Sooner or later the banks will have to forclose here and simply get what they can for the vessels or they will have to write off some of their claims to encourage yet another round of investment in a loss making company whose assets are held at book value at significantly more than could be realised in a sale process. NAO fleet Value.png

That last comment above is based on using a 10 year average of PSV rates and utilisation levels. At some point the reality of needing new cash to pour into operating losses is going to collide with their “beliefs” as NAO don’t have enough cash to last until (if?) rates return to 10 year historic averages. It is very hard to see the upside for any potential investor here even if the banks wrote off 100% of their claims, something they are clearly unlikely to do.

Not that there is room at the survivors table for all the medium-sized companies either. Bankers for Maersk Supply Service have also been taking soundings for a buyer. They are seeking top dollar for a company unfortunate enough to order the Starfish class of vessels just before the market peaked, but even more unfortunate enough to have a parent able to honour the group guarantees to pay for the vessels on delivery. In 2017 they stopped posting financial results on the website but are well understood to be losing significant amounts of cash at an operating profit level.

Maersk Group are listing Maersk Drilling as they have been unable to find a buyer, but they were able to organise banks willing to back the company with debt facilities. It is very hard to see a similar situation arising with Maersk Supply where no realistic path to profitability can be plotted and creditors would remain exposed to large operating losses.

Maersk Supply has also been trying to build a contracting business when the market for projects in the UKCS has reduced by 66%. They have no competitive advantage and nothing to offer an oversupplied market. All that will happen here is they will burn OpEx trying to do this and eventually, when all the other options have failed, they will do the right thing and shut the contracting business down. While all the tier 1 (and 2) contractors have significant excess capacity there is no room in the market for a new tier 2 contractor whose sole purpose is to cross-subsidize utilisation from their vessel fleet. A JV with Maersk Drilling to work on decommissioning is unlikely to yeild anything of scale that someone with outside capital would find value in paying for.

Maersk Supply is at the upper end of the adjustment band of companies that are unlikely to survive without some sort of dramatic and unforecast change in market circumstances. Protected in better times by a massive corporate parent, and with a similar proptionate cost base, it is now exposed as a massive cash drag as its owner tries to protect its investment grade credit rating. MSS offers insignificant scale in the market, ongoing cash losses, and a very high cost base reminiscent of better times in a geographic location where this is hard to change. Maersk Supply simply isn’t a viable standalone business at the moment without a massive equity injection.

AP Moller-Maersk have vowed to do whatever it takes to protect their investment grade credit rating, at some point the material losses being generated in MSS will force their hand here. As more disparate parts of APMM are divested the trading performance of MSS will become something that will need to be cauterised.

The future of offshore supply can be seen in Asia where small nimble  companies with very low costs make money on wafer thin margins. Traders. Vessels are worked to death and meet minimum local standards but nothing more. If Standard Drilling/ Fletcher can bring ex-DP I vessels to the North Sea to compete against NAO then welcome to the future of the North Sea supply market because that is how you drive OpEx down 40%.

NAO and Maersk Supply, like a lot of other companies in the industry, found investors over the last couple of years (one external and one internal) who believed that the market would return to previous levels and it was worth funding the interim period. At each round of fundraising this becomes an ever more unlikely outcome and the costs of this rise. Slowly but surely some companies will be unable to convince potential investors that they will be the one who makes it through to the (mythical?) recovery. This slow grinding down of capacity and capital is how the industry looks set to rebalance.

Shale doesn’t have a cash flow issue …and the limits of expansion…

Yesterday the $WSJ had this article on the economics and cash flows of the shale industry. The overall point is logical that if cost increases continue the cost of capital may go up for shale producers and point to it reaching the economic limits of its expansion. I agree with the general thrust of the article in that if the industry isn’t as profitable as forecast the cost of capital will increase, but this comment is being taken out of context by some:


Of course they didn’t… they are investing for even higher production next year… the comment “within their means” is pejorative and not a reflection of economic reality. That is a sign of confidence from the firms and their financial backers that their output can be sold at a profitable price. The price signal from both the oil and the capital markets is strong.

I also received a comment yesterday with a link to this comment. I don’t think this is a big deal to anyone with a basic understanding of finance because they get this… but then again I have lost count of the number of people who repeat back to me that no one makes money from shale.

I wonder if this isn’t becoming part of the great “Gotcha” narrative that aims to prove that shale isn’t a viable production methodology? Like the CEO of Shell is going to wake up next Tuesday and say “after reading the article in the WSJ we are going to stop investing in shale. Thank goodness I read that or I would never have realised we will never make money from it!” As if those investing literally tens of billions had no idea of the cash flow profile of their assets?

The overall article is interesting only in that it points to what appears to be the current “productive efficiency” of shale, not its demise. The point of the article isn’t that you can’t make money from shale it is that at the margin now it is becoming less profitable and that may affect the pricing of capital. Bear in mind before you read the rest of this post the scale of the increase in absolute oil production shown in the graph above and the amount of capital required to finance this.

For those not versed in accounting cash flow negative might seem like a big deal but it’s not. A casflow statement is made up of Cash From Operations [CFO] (+/-) Cash flows from investing [CFI](+/-) Cash flows from financing [CFF]. It balances with the cash at bank at the start of the period and at the end. Free Cash Flow to the firm is simply the sum of the first two… You would expect the number to be negative in a capital-intensive industry, like shale oil extraction, when you are seeking to grow output volumes significantly, particularly when a number of firms are new entrants into the industry and not financing from retained earnings. You are spending capital to get future revenue and you need to borrow or raise equity to do this. Collectively as all the firms in the industry deepen the capital base for ever higher production they are using more cash than they are generating currently. (I am aware that there are a number of definitions of Free Cash Flow but this appears to be the Factset one and the generally accepted one of FCFF).

If you buy an offshore drilling rig for $1bn and get 100m in operating cash flow for year 1 then your (highly simplified and representative) cash flow statement reads: CFO +100m: CFI -$1bn. That is your “Free Cash Flow” [FCF] is -$900m. It is balanced (all going well) by CFF +900. You own an oil rig that lasts for 20 years but in year 1 you were down $900m in FCF. You can buy as many rigs as you want and be FCF negative (like Seadrill) for as long as you can keep CFF >= CFO+ CFI  i.e. you have access to debt or equity markets. That is all that is happening in shale collectively.

If these were operating cash flow negative then there would be a massive issue. But as this research from the Dallas Federal Reserve (March 2018) makes clear there is no problem with operating cash:


Or indeed with profitably drilling wells at the current oil price (i.e. including financing):


For as long as investors believe that in the future the oil price attainable by these E&P companies is sufficient to return capital, and funding markets remain open, then spending more on Operating Income + CapEx combined is no problem. There is rollover risk in the debt but that is a seperate risk and appears to be pretty minimal at the moment.

Pioneer is an embodiment of this: in the first six months of 2018 it generated ~$1.5bn from operations (i.e. selling oil and gas) [CFO], spent ~$1bn on investments (actually nearly $2bn but it sold some stuff as well) [CFI], and then paid back debt of $450m and purchased ~$50m of shares. But some smaller companies who have come in recently will have spent far more on CapEx than they will earn in CFO.

When I have talked about the ‘virtuous cycle’ of capital deepening in prior posts this is part of that network effect of decreasing risks and increasing returns for all involved in the ecosystem. E.g. if Trafigura build an export facility for 2m b/per day it lowers the risk for every E&P company (and their financiers) that they can sell more oil profitably. So more investment comes into the sector in an ever-expanding circle, lower costs, replacing labour with capital. That is what appears to be happening here. The limits of this process are there and are hinted at in the WSJ:


Permian production will be up 19-24% according to Pioneer so it’s not all bad. Costs are increasing as the Permian reaches the constraints of labour and capital as has been well documented. Some of these will disappear with new pipelines and other capital deepening, e.g. a replacement of capital over labour as excess surplus is currently trucked or railed out, but some will continue given the huge increase in absolute production volumes. It is no surprise that with such a huge percentage increase in production that at the margin each incremental barrel becomes more expensive in the short-run, but then the capital deepening effect will kick in and the long-run cost curve will decline, as always in mass-production, and then the unit costs drop again… ad infinitum

Pioneer are saying with that statement is that their marginal output on capital is declining slightly this year as cost increases have not kept pace with productivity improvements. That isn’t surprising because the sheer volume of output increased has consistently surprised on the upside. If the project costs increase 10% and this isn’t covered with higher prices and/or productivity improvements then investors will change their price of capital to reflect diminished expectations.


But this production capacity isn’t going away. The rigs have been built. The pipelines have been, or are being, built; the same goes for export terminals etc. The capital base of the industry has increased massively and is facing some teething problems. But in a little 4 over years the US tight oil industry has driven US production up to over 11m b/ per day in 2018, over 6m b/ per day of that from shale up from ~4m b/ per day in 2017.

What should really worry those in the offshore community is that this is an industry that increased production 50% in a calendar year before hitting the limits of economic growth, and it did this while increasing productivity and lowering unit costs. Someone isn’t waking up next Tuesday and realising it has all been a massive mistake and turning the tap of funding or production off. The US shale industry is a deep and entrenched part of the energy mix now. Current forecasts might be out by a few hundred thousand barrels a day but they are not going to be out by millions. This production is real and permanent with profound implications.

The core logic of the WSJ article is surely right: A rise in the costs of shale relative to output signals the limit of the economic efficiency and therefore the diminishing returns to capital may make it more expensive for shale E&P firms to fund new projects. Shale and offshore compete for E&P company CapEx and if the cost of funding shale projects rises (on a productivity measured basis) that should increase relative demand for offshore as a substitute. But the Free Cash Flow from an offshore project is massively negative in the short-run and over time has higher yields, whereas the reduced CapEx commitment, despite its lower margin, is one of the chief attractions of shale. Cash for investment is not the issue.

I think it sits uncomfortably with forecasters who claim that day rates for jack-ups will double within two years, or other such notions, and it does not seem to be incorporated in the strategic planning assumptions of a large number of offshore companies or investors where the logical outcomes of such data sit uncomfortably. The offshore industry built a fleet to handle 2013 demand when shale was producing ~2.5m barrels a day, it is now producing 6m and is growing faster than the overall oil market growth and forecast to do so until 2021 at least.

Hard strategic questions arise for the offshore industry: how do we compete in an industry which faces potentially declining market share for our underlying product at the margin? How do we compete in an industry when a competitor with a different business model has taken 10% of global market share in the space of 5 years and we buy 25 year assets funded on short-term contracts? What level of asset base shrinkage does the offshore industry require to be competitive? How many firms will have to liquidate given this necessary shrinkage? What will the surviving firms look like? How much can they realistically expect to make? What are our assets worth?

There are a lot more questions based around this logic. But if you are simply expecting a day-rate increase and a demand side boom based on shale magically running out of cash at some future point I think you are going to be very disappointed.

Capital reallocation and oil prices…

The above graph comes from Ocean Rig in their latest results where despite coming in with numbers well below expectations they are doing a lot of tendering. At the same time ICIS published this chart…


It is my (strongly held) view that these two data points are in fact correlated.

I saw an offshore company this week post a link to the oil price as if this was proof they had a viable business model. Despite the rise in the oil price in the last year there has been only a marginal improvement in conditions for most companies with offshore asset exposure.  There is sufficient evidence around now that the shape and level of the demand curve for offshore services, particularly at the margin, is in fact determined by the marginal rate of substitution of shale for offshore by E&P companies. That is a very different demand curve to one that moved almost in perfect correlation to the oil price in past periods.


Source: BH Rig Count, IEA Oil Price, TT

This week two large transactions took place in the pipeline space. The commonality in both is new money comping into pipeline assets that E&P companies own. Over time the E&P companies hope they make more money producing oil than transporting it. But they have found some investors who for a lower rate of return are happy just carrying the stuff. More capital is raised and the cycle continues. On Friday as well Exxon Mobil was confirmed as the anchor customer for a new $2bn Permian Highway pipe. These are serious amounts of capital with the Apache and Oxy deals alone valued combined at over $6bn and shale producers confirming they are raising Capex.

When I people talk of an offshore “recovery” as a certainty I often wonder what they mean and what they think will happen to shale in the US? There strike me as only three outcomes:

  1. At some point everyone realises that shale technology doesn’t work in an economic sense and that this investment boom has all been a tremendous waste of money. Everyone stops investing in shale and goes back to using offshore projects as the new source of supply. I regard this as unlikely in the extreme.
  2. Technology in shale extraction reaches a peak and unit costs struggle to drop below current levels. In particular sand and water as inputs (which are not subject to dramatic productivity improvements but are a major cost) rise in cost terms and lower overall profitability at marginal levels of production. This would lead to a gradual reduction in investment as a proportion of total E&P CapEx and a rebalancing to offshore. Possible.
  3. Capital deepening and investment combined with technology improvements cause a virtuous cycle in which per unit costs are reduced consistently over many years. Such a scenario, and one I think is by far the most likely, would place consistent deflationary pressure on the production price of oil and would lead to shale expanding market share and taking a larger absolute share of E&P CapEx budgets on a global basis. This process has been the hallmark of the US mass production economy and has been repliacted in many industries from automobiles to semiconductors. Offshore would still be competitive but would be under constant deflationary pressure and given the long life of the assets and the supply demand balance would gradually converge at a “normal” profit level where the cost of capital was covered by profits.

I don’t know what the upper limit of shale expansion in terms of production capacity. I guess we are there or near-abouts there at the moment, but I also don’t really see what will make it stop apart from the limits or organizational ability and manpower?

It is worth noting that a lot of shale has been sold for significantly less than the highly visible WTI price (delivery Midland  not Cushing):


And Bakken production is at a record:


Each area creates its own little ecosystem which deepens the capital base and either lowers the unit costs or takes in used marginal capital (i.e. depreciated rigs) and works them to death. The infrastructure created by the temporary move away from the Permian may just create other marginal areas of production.

I think “the recovery”, defined here as offshore taking production and CapEx share off shale, looks something like this model from HSBC:


I suspect it’s about 2021 under this scenario that the price signal starts kicking in to E&P companies that at the margin there are more attractive investment opportunities to hit the green light on. That’s a long way off and is completely dependent on some stability in the market until then, but under a fixed set of assumptions seems reasonable. Note however the continued growth of shale which must take potential volume from offshore at the margin.

The offshore industry needs to get to grips with the challenges this presents (I have some more posts on this on the Shale tag). Mass production is deflationary, indeed that is it’s purpose. Shale is deflationary in the sense of adding supply to the world market but also deflationary in terms of consistently lowering unit costs via improving the efficiency of the extraction process and the technology. Offshore was competitive because it opened up a vast new source of supply, but it has not been deflationary on a cost basis (until the crash caused its assets to be offered at below their economic cost).

I’ve used this graph before (it comes from this great article) it highlights that the 1980s and 1990s had generally deflationary oil prices based on tight-monetary policy and weaker economic growth expectations. Ex-Asia the second part of that equation is a given today and US$ strength means oils isn’t cheap in developing countries. As the last couple of weeks have reminded us there is no natural law that requires the oil price to be in a constant upward trajectory.

Inflation adjusted WTI price.png


Dead man walking…

Hilton Barber: [at Matthew Poncelet’s appeals hearing] The death penalty. It’s nothin’ new; it’s been with us for centuries. We’ve buried people alive; lopped off their heads with an axe; burned them alive at a public square… gruesome spectacles. In this century, we kept searchin’ for more and more *humane* ways… of killin’ people that we didn’t like. We’ve shot ’em with firing squads; suffocated ’em, in the gas chamber. But now… Now we have developed a device that is the most humane of all. Lethal injection. We strap the guy up. We anesthetize him with shot number one; then we give him shot number two, and that implodes his lungs, and shot number three stops… his heart. We put ’em to death just like an old horse. His face just, goes to sleep, while, inside, his organs are going through armageddon. The muscles of his face would twist, and contort, and pull, but you see, shot number one relaxes all those muscles so we don’t have to see any horror show… We don’t have to taste the blood of revenge on our lips, while this, human being’s organs writhe, and twist, and contort… We just sit there, quietly. Nod our heads, and say: ‘Justice has been done.’

Dead Man Walking

Let’s just be clear: there is no chance of Viking Supply suriving as an economic entity. The question is around the method of demise not the ultimate question of it. For those aware of my history with the Odin Viking there are no surprises, and the irony of it’s association with “war, death divination, and magic” is not lost on me.

GOL Offshore was also put into liquidation last week. Again a subscale operator with no discernable point of difference from all the other assets and service providers out there.

This is how the industry in the supply side will rebalance. Small operators with commodity ships, no competitive advantage, and simply not enough asset value or liquidity to survive. But there are a lot more to come.  These size of these companies are small enough for the banks to write-off and are simply not worth saving. When the asset sales are done Viking Supply will effectively be in wind-down mode, the result of structural forces more than any other reason, but a necessary step to economic rationality. I don’t know what the minimum efficient scale is for a supply company but it’s a lot more than 15 vessels.

The largest companies in the supply industry have either large parent companies (Maersk, Swire, etc) or so much asset value post-restrcturing there will always be some logic to put money into to see the next year (Tidewater). For those without a cheap local cost base and contacts or without the advanatges of financial scale a grim existence beckons.

The real question is do the Viking Supply results presage the Q2 results for other operators or have they lost significant market share in the AHTS space? I think you can take it as a given that this comment reflects the general industry conditions:

The offshore supply market was very disappointing throughout the first half year, and the very weak market has caused both fixture rates and utilization to remain on unsatisfactory levels.

The real question isn’t who is selling the shares of companies like Viking, Solstad, and Standard Drilling but who on earth is buying them? The banks were desperate for Viking to survive but even they have abandoned hope now. Expect more banks and investors to do the same in offshore supply.

My holiday reading…

I’m off to Spain for some reading and beach time on Wednesday… Strangely prescient reading awaits …

If anyone wants a book recommendations one of favourite economic history books is The Wages of Destruction (but The Deluge is up there as well) and The Museum of Innocence is one of my favourite novels. I went to Turkey for the first time in 2001 and then everyone wanted dollars, then I went back four years later and everyone wanted €. The script looks written for a currency crisis here when the President asks the population to change $ into Lira as an act of patriotism, and so when I next go back to Turkey they may well be looking for Yuan if David Goldman is right.

The graph above just shows that Turkey isn’t going to stop buying Iranian oil. They will just barter for it and actually end up paying less in $ terms. Russia and China are getting a back door channel to the whole region the longer this keeps up.

Permian export capacity, marginal investment, and disintermediation…

“O human race, born to fly upward, wherefore at a little wind dost thou so fall?”
Dante Alighieri, The Divine Comedy

Big news on capital investment in Permian takeout capacity today:  Trafigura Group and Enterprise Product Partners are independently looking to build significant VLCC  export terminals in Houston. The two combined terminals would allow for 2.4m barrels of crude a day to flow out of Houston ports: given that global liquids production is ~100m barrels a day these two terminals allow for around 2.4% of global production to be reallocated through one location.

Permian pipeline capacity is growing by 2m barrels in the next two years. If you were wondering where that oil was going this is one large trading house and one infrastructure provider making their respective moves. This is just a further example of the continued capital deepening in the region that will only further enhance and encourage greater investment in shale-based production.

One cannot help but note the contrast between the Trafigura business model and that of an offshore energy company. Trafigura is providing infrastructure and distribution capability to a whole host of smaller E&P companies that will concentrate on production and require CapEx only to hook-up to a pipeline (or less commonly a rail) network. Trafigura gets (at least) an infrastructure style return on the export facility and full exposure to the commodity price and volume as a trading house (which is what they want). But what it doesn’t have to do is develop a major E&P presence in the basin : in economics/ management speak they have disintermediated the E&P supply chain. It might sound like a dot-com era buzzword but it’s real.

Trafigura has the perfect supplier base of small companies, who wish to sell 100% of output at the marginal (i.e. spot market) price, and are constantly seeking innovative ways to extract that product at the lowest possible cost. In an industry where a host of smaller companies supply rigs and crews to drill wells the expensive coordination costs of this are being farmed out to the smaller companies. Very low barriers to entry, literally $10m per well and full rig crews for only a deposit, will ensure that greater offtake capacity keeps margins capped (at the level required to induce new firms) while Trafigura controls returns that require capital and market power. It is the sort of market and business that locks in structurally higher profits for the infrastructure and distribution arm while pushing CapEx back to E&P companies and their supply chain. If oil prices slump and some of the production companies go bankrupt then their assets will simply attract new buyers at a level that reflects the marginal cost of production and they will still need export and distribution facilities.

This for offshore is where competition for marginal investment dollars resides. A core of finance theory is that returns are linked to risk. You might well be able to get a lower per barrel cost from an offshore field but you have to risk your capital for a significantly longer period of time in an era of very volatile oil prices. Not only that but most offshore developments require that you invest in subsea processing equipment and offtake capability to get to a shared pipeline or increasingly to a FPSO for larger developments. Finance theory also teaches you that all projects that are NPV positive should be funded but the institutional mechanics of raising capital, and the impact of market sentiment on sector investments, mean that isn’t always the case (although really you could just argue that the finance providers have a different view of the risk involved).

Regardless, as the graph at the top of this article shows capital expenditure to offshore projects has declined ~29%!! as a proportion of the total allocation since 2016 (from 41% to 29%) while capital to onshore conventional and shale has grown (IEA) . This is well below the 2000-2010 average and if continued is a large structural industry change. Competition for capital and marginal production is driving this change and there is real competition. There is no ‘inflection point’ for offshore demand, or ‘recovery to prepare for’, without a marked change in this trend. Offshore is losing the battle for capital at the margin and remains competitive only by supplying assets below their economic cost.

Since the downturn in 2014 the holy grail of subsea investment has been to try and find investors willing to buy and lease the infrastructure as opposed to taking E&P risk. The problems with such an idea are legion: the kit is very site and customer specific, has limited residual value, and may struggle to get seniority over the reserves below in the event of a default driven by low oil prices. It is in short very difficult to create something that isn’t simply quasi- equity in the field and surely should be priced at the same level? The ability to genuinely split exploration and production risk from distribution risk, the hallmark of the US midstream system, offers a financing and business model innovation that makes it easier to allow large sums of capital to be raised and further deepen the capital base for production in the region. Finance matters in innovation.

As I keep saying this isn’t the end of offshore but it heralds a new kind of offshore surely? Large deepwater developments allow fully integrated E&P majors to take signficant development complexity, capital, timing, and offtake risk. These companies talk of ‘advantaged oil’ and they have it in these developments. Trading houses with export capability and infrastructure have advantaged oil in their network of production companies who aim to sell 100% of output at the margin, none of whom are large enough to impact the price they pay for the product, but mid sized offshore companies strike me as under real threat and limited in size to the proportion of oil shale/tight oil can supply.

Mid-sized offshore companies do not have the portfolio advantages that large oil companies do. Every development represents a significant fraction of their investment plans and there is a limit to the technical complexity and capital required of projects they can undertake. Previously their ‘advantaged oil’ was access to a resource basin that was needed but did not move the production needle for larger companies. As riskier investments they raised capital on smaller markets (AIM, Oslo OTC, TSX) and used reserves-based financing and bonds along with farmout agreements. But this took time and the higher leverage levels make this risky. The cost of equity, when available, is much higher than in the past because the expectation is that the price of oil will be more volatile. And now the returns are capped by the marginal cost and volumes at which shale companies can supply, which is a new and significant risk factor, particularly in an investment with a multi-year gestation period.

Yet these small-mid sized offshore E&P companies represented the demand at the margin for offshore assets. Large complex drilling campaigns and projects for tier 1 E&P companies always attracted good bids and a relatively efficient price from contractors, but smaller regional projects did not. The margins were higher and the risks greater. On the IRM side these companies negotiated harder on the price but they still had a volume of work that needed to be undertaken. It is these companies, their inability to get finance because of their complete lack of advantaged oil, that are also ensuring now that CapEx (and therefore demand) is not recovering as in previous cycles. These E&P companies are price taking firms with signficant operational leverage/fixed commitments and limited financial or operational flexibility in the short-term. Currently they rely on developments being profitable via the supply chain providing assets below their economic cost. That is not a great strategic position to be in. When there was no competition for your product the story was completely different, but the shale revolution is real.

This chart shows you that demand growth for crude slowed 1% year-on-year for two months and the market became oversupplied (hence the drop in the price of oil recently):


Investors in oil closely watch volatility indicators like this and as I have said before the logical investment strategy is to invest more secure lower margin companies.

The three major risks to supply listed hy Woodmac at the moment are Venezuela, Libya, and Iran. These are geopolitical risks that could easily end in the short-run. Iran is self-induced and the situation in Venzuela so unsustainable (the real question isn’t why someone tried to assasinate Maduro but why everyone else isn’t?) that it surely cannot last? In prior eras the solution was to build long lasting production capacity in politically stable places. Now surely the solution is to use temporary production capacity where possible and let the price signal take some of the strain?

I think it is axiomatic that offshore cannot boom without a recovery in offshore CapEx spending. At the margin offshore has ceded significant market share in this competition to shale. Major structural change will be needed in the industry before the situation reverses based on current trends.

Absolute versus relative…. shale and conventional competition at the margin…


“An uptick of 30% from the abnormally low levels in 2017 might seem encouraging, but E&P players are currently facing a low reserve replacement ratio, on average of less than 10%. This is worrisome considering the impact on global oil supply in long term,” says Espen Erlingsen, Head of Upstream Research at Rystad Energy.

I think this is simply a badly worded comment from Rystad where they mean E&P added less than 10% to overall reserves from  conventional sources. In a relative sense I think Rystad are arguing that reserve replacement has been low (i.e. relative to total reserves). The comment is hard to square with the graphic at the top from the EIA and this comment which makes clear in an absolute sense there is no problem:

In 2017, a group of the world’s largest publicly traded oil and natural gas producers added more hydrocarbons to their resource base than in any year since 2013, according to the annual reports of 83 exploration and production companies. Collectively, these companies added a net 8.2 billion barrels of oil equivalent (BOE) to their proved reserves during 2017, which totaled 277 billion BOE at the end of the year. Exploration and development (E&D) spending in 2017 increased 11% from 2016 levels but remained 47% lower than 2013 levels.

Of the 83 companies, 18 held more than 80% of the 277 billion BOE in proved reserves at the end of 2017. [Emphasis added].

Rystad seem to be measuring “conventional” resources only which in this world strikes me as an irrelevant metric. Shale and Conventional may not be perfect substitutes  (some refineries for instance cannot process light crude in the short-run) but they are close. Either way we don’t appear to be facing an imminent supply shortage caused by under-investment in early stage E&P activity. And in fact the EIA says:

First-quarter 2018 capital expenditures for this set of companies were 16% higher than in first-quarter 2017, suggesting that many of these companies have increased their E&D budgets, which will likely contribute to further organic proved reserves additions in 2018.

Clearly they are measuring two different things, but I still don’t get the Rystad conclusion? The EIA uses proven and economically achievable reserves  on net discoveries and is surely a more relevant metric? Of course it doesn’t support a “Preparing for the Recovery” thesis at all.

If you want a graphic illustration why European offshore companies have been the most exposed to the downturn in offshore CapEx look at the first chart:


On a rolling three year average investment in Europe, which is predominantly offshore, has dropped to around 30% of previous levels. A far greater proportion than any other region and the reason is obviously that it is a high cost area of marginal production.

You can really see the productivity improvement in the second graph: Capex peaked at over $30 per BOE in 2014 and is heading down for $15 per BOE. The supply chain having gone long on fixed assets hoping to profit from a production boom has just over capitalised and allowed the E&P companies to massively reduce development spend in a downturn.

What the EIA and the Rystad combined show is the profound changes taking place in the production of oil and gas. The data show (partially and indirectly) the marginal investment curves for shale versus offshore/onshore conventional. Rystad show that conventional oil and gas replacement is dropping as a proportion of the energy mix. The EIA data shows the drop in marginal production areas: the huge drop in European CapEx, almost exclusively offshore and extremely expensive on a per BOE equivalent, shows that at the marginal capital is being redeployed in other production techniques.

But what the data emphatically does not show is anything to worry about long-term from a supply perspective.