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):

IMG_0731.JPG

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.

Weekend shale read… The Red Queen for offshore…

“Well, in our country,” said Alice, still panting a little, “you’d generally get to somewhere else—if you run very fast for a long time, as we’ve been doing.”

“A slow sort of country!” said the Queen. “Now, here, you see, it takes all the running you can do, to keep in the same place. If you want to get somewhere else, you must run at least twice as fast as that!”

Alice in Wonderland, Lewis Carrol

Applied to a business context, the Red Queen can be seen as a contest in which each firm’s performance depends on the firm’s matching or exceeding the actions of rivals. In these contests, performance increases gained by one firm as a result of innovative actions tend to lead to a performance decrease in other firms. The only way rival firms in such competitive races can maintain their performance relative to others is by taking actions of their own. Each firm is forced by the others in an industry to participate in continuous and escalating actions and development that are such that all the firms end up racing as fast as they can just to stand still relative to competitors.

THE RED QUEEN EFFECT: COMPETITIVE ACTIONS AND FIRM PERFORMANCE

Derfus et al., 2008

 

Stressing output is the key to improving productivity, while looking to increase activity can result in just the opposite.

Paul Gauguin

 

The IEA has done a review of shale companies financing and for those hoping that they represent some sort of ephemeral phenomenon that will pass as soon as the junk bond market closes, well rates decline, or some other exogenous event arises, they are likely to be disappointed. It’s a short read and well worth the effort. I called shale an industrial revolution the other day and the IEA post is a good short precis on how this came about in financial stages.

SPE also has had some good articles recently on the constant productivity the shale industry is using to drive down costs. This one on Equinor for example:

One of the drawbacks of the status quo is that it requires small armies of field personnel to interpret SCADA data and then adjust set-points to get pumping units back into optimal operating ranges. This manual process can consume half-an-hour per well to complete; downtime that quickly adds up in a field of hundreds.

“What we are talking about is having the machine do that entire workflow,” Chris Robart, Ambyint’s president of US operations said…

The Bakken project comes after a pilot that included 50 of Equinor’s wells, which saw a net production increase of 6%—considerably larger uplift figures were seen from those wells suffering from under-pumping.

Or this one dealing with Parent/ Child wells, which a few months ago seemed to be the latest reason to explain why shale wasn’t a sustainable form of energy, but the industry has solved part of this problem through “cube development”:

But the prize for coining the term cube development goes to Encana Corporation, which says the strategy has increased early well productivity in one of its Permian fields by 70% over the past 2 years. Despite the term’s growing popularity within engineering circles, some companies continue to use different terms such as QEP’s “tank-style completions” for what is seen as the same general practice.

I don’t understand the technology but I have faith that day-in day-out new techniques are being developed that will drive down the costs of extraction and production in the shale industry. You need to be a technical pessimist, which in this age is hard, to believe this productivity direction cannot continue (see Citi here).

Over time the offshore industry will change to compete with shale. The economic force of competition will ensure this. But in order to compete it will need to reduce the cost and time of being offshore dramatically and focuson on high-flow low lift cost projects. Something well underway in the Gulf of Mexico at the moment.

There are huge moves in offshore to improve productivity: all righty focused on spending lowering cost and reducing time to first oil. Some, but by no means all, contractors focused on engineering are starting to see improved profitability. But the sunk investments made in offshore vessels, jack-ups, and rigs have largely had their equity wiped out in the last few years and this is enabling the offshore industry to compete on price and risk in terms of capital allocation from E&P companies. For as long as that is it’s only, or major, competitive advantage all that beckons is an industry that slowly runs down its capital base until project cost inflation can rise. Something that becomes ever more distant the more competitive shale becomes. I realise it’s a bleak prognosis but there isn’t much else on offer.

What is an offshore construction vessel worth?

There is an article from Subsea World News here that is sure to have bank risk officers and CFOs choking over their coffee… VesselValues new OCV is launching a new analytics tool for the sector. The ten most valuable vessels in the OCV sector are apparently:

  • Normand Maximus $189m;
  • Fortitude $99 million;
  • Deep Explorer $97 million;
  • Siem Helix 2 $96 million;
  • Seven Kestrel $95 million;
  • Siem Helix 1 $95 million;
  • Island Venture $94 million;
  • Viking Neptun $92 million;
  • Far Sentinel $90 million;
  • Far Sleipner $89 million;

Firstly, look at the depreciation this would imply? As an example the Maximus was delivered in 2016 at a contract price of USD $367m. So in less than 2 years the vessel has dropped about 48% in value. Similarly the two new DSVs the Seven Kestrel and Deep Explorer appear to be worth about 67% of value for a little over two years depreciation.

Secondly, the methodology. I broadly agree with using an economic fundamentals approach to valuation. And I definitely agree that in a future of lower SURF project margins that these assets have a lower price than would have been implied when the vessels were ordered. I have doubts that you can seperate out completely the value of a reel-lay ship like Maximus from the value of the projects it works on but you need to start somewhere. It is clear that SURF projects will have a lower structural margin going forward and logically this must be reflected in a vessel’s value so I agree with the overall idea of what is being said.

There is a spot market for DSVs on the other hand so their value must reflect this as well as the SURF projects market where larger contractors traditionally cross-subsidised their investment in these assets. A 33% reduction in value in two years might well reflect an ongoing structural change in the North Sea DSV market and is consistent with the Nor/Boskalis transactions on an ongoing basis. This adds weight to the fact York have overpaid significantly for Bibby, who would be unable to add any future capacity to the DSV market in the pricing model this would imply and not even be earning enough to justify a replacement asset. Given the Polaris will need a fourth special survey next year, and is operating at below economic value at current market rates, even justifying the cost of the drydock in cash terms on a rational basis is difficult.

Depreciation levels like this imply clearly that the industry needs less capital in it and a supply side reduction to adjust to normal levels. Technip and Subsea 7 are big enough to trade through this and will realise the reality of similar figures internally even if they don’t take a writedown to reflect this. Boskalis looks to have purchased at fair value not bargain value to enter the North Sea DSV market. SolstadFarstad on the hand have major financial issues and Saipem locked into a charter rate for the next 8 years at way above market rates, but with earnings dependent on the current market, will have to admit that while the Maximus might be a project enabler it will also be a significant drag on operational earnings. The VesselsValue number seems to be a fair reflection of what that overall number might look like.

The longer the “offshore recovery” remains illusory the harder it will be for banks, CFOs, and auditors to ignore the reality of some sort of rational, economic value criteria, for offshore assets based on the cash flows the assets can actually generate.