Market forecasts as structural breaks….[Wonkish]

Not for everyone this post but important if you are involved in strategic planning. The above chart is from the latest Subsea 7 Q1 numbers. The problem I have with these charts is what statisticians call “structural breaks“. Basically if the underlying data has changed then you need to change your forecast methodology. As I have argued here and here (although it’s a general themse of this blog) I think there is sufficient evidence that large E&P companies are commissioning less offshore projects when they become economically viable in the past on NPV basis. I am not sure that all the forecast models reflect this.

This break in the historical patterns has really important forecasting implications because when you see whichever market forecast  it has made an assumption, whether formally through a regression model or on a project-by-project basis, that x number of projects will be commissioned at y price of oil (outside of short term data which logs actual approvals). If there has been a stuctural change in the demand side then y (commissioned offshore projects) will be lower, and on a lower trajectory to x (the oil price) permanently, than past cycles.

E&P companies are not perfectly rational. As the oil price gets to $60 there is no set programme that triggers a project. For sure the longer the price stays high it increases the probability of projects being commissioned but it is a probability and the time scale of has changed I would argue. I think it is why demand has surprised many on the downside because there has been a change in the forecast relationship between offshore projects and the spot price of oil.


A supply contraction and rising oil prices…

The comments above are from Schlumberger’s results last week. Note the comments about the only possible sources of short-term supply increase. I think SLB are ignoring increased maintenance spending to bring shut-in wells back but this is probably not a major number.

It is worth noting that this era of rising oil prices, if they remain, is driven by OPEC trying to limit supply to drive the price up for macroeconomic reasons, and is therefore different to the 2008 -2014 increase where the dominant narrative was to increase supply for a booming economy. The narrative counts.

Here is another reason any “recovery”, or boom 5.0, or whatever, in oil prices will be:

Crude Shipments

So any recovery will be just like before only different. Some change will be cyclical and just like the past but some has clearly been secular. Business plans that assume a general “recovery” as being disingenuous.

I ran a very hot half marathon today (Southampton). Anyone who enjoys this blog and feels it has some economic value please make a contribution to the Hospice North Shore (NZ) (an amazing place that took amazing care of my Mum at the end and to whom I am forever in their debt) or the Motor Neurone Disease Association UK.

Thanks in advance.

“This time it’s different…” … But it really is…

I sometimes think the brief downturn of 2008/2009 in oil prices and offshore demand has a lot to do with how the downturn that started in 2014 is interpreted. I was there, got the t-shirt, and it was brutal, but it was short and there was an asset base that was vastly smaller than the current active (or potentially) rig and vessel fleet of today.

The graph above show’s the EIA forecast for US crude oil production by grade (that includes onshore and offshore). Unless you believe this graph to be completely wrong you would have to accept there has been a significant structural change in the industry… as a comparison have a look at the US production levels leading up to the 2008/09 downturn:

US oil production 1986 -2010.jpeg

US domestic oil production was on a downward trend at 5m barrels a day, slowly rising in 2009, before its meteroric 2010 rise. In 2009 the logical dominant narrative, both in investment terms, and operational terms, was that offshore production had to be increased: there was no alternative. Shale was expensive, companies were still thinking oil sands production was a viable technology within current constraints to keep pursuing, and although the investment dip was brutal it was a single season, and the spot price recovered quickly as well.

Now the graph at the top is the dominant logic. There is a self-reinforcing cycle here that is leading investors at the margin to use shale as the swing production method of choice. From 5m barrels a day to 10m and realistic scenarios involve this being 12m. Not only this as a marginal production technology shale is shorter cycle and uses much less initial capex, the trade-off being lower overall profitability. But on a risk-weighted and time-commitment basis it is a far less intensive production technology. As I keep saying here everything Spencer Dale wrote is coming to fruition here over the shale doubters. The force of economics triumphs over engineering constraints of the current technology curve yet again!

Change at the margin it is occurring every day when investment managers at either E&P companies, or fund managers/PE investors, decide to back a shale project over an offshore project. No one is saying offshore is going away, but at the margin the total volume of decisions made one way or the other will dictate what a “recovery” for offshore looks like. There is no doubt this summer will be busier than last summer for work, particularly for IRM where the spending taps have been loosened a little, but the supply situation is such that no one is reporting increased rates it’s all about utilisation.

My point with this, as I constantly stress, isn’t that offshore is going to zero, but that any recovery in offshore is going to look very different to any prior to 1986, because there is now a viable swing producer with a very different commitment profile. Offshore will be part of the energy solution not THE solution, and that is a very different dynamic.

Up until 2010 offshore was the only viable solution so there was a reasonable belief that this was cyclical pause in investment driven by a cash flow issues oil companies were having with the spot oil price. I am just not sure that is a reasonable assumption now?

Frac spread count

The Frac Spread Count is the equivalent of the BH rig count for frac spreads. You can see the tremendous growth in onshore capital equipment utilised that has occurred in a fairly short space of time. This process of capital deepening will not go away, this equipment, which is getting more efficient, will need to be traded even if the price of oil drops. Like vessels it will price at marginal cost if required to keep utilisation high.

And shale appears to be getting ever more efficient:

Now a second revolution is on the horizon as operators prepare to re-enter those wells that launched the first revolution and implement secondary recovery projects. That can consist of operators reinjecting gas into the reservoir to restore pressure and then producing the additional crude and natural gas…

the Permian Basin has been producing for close to 100 years and “we’re not even close to getting all the oil.”

Which led the IEA to issue this graph this morning with the byline “US shale oil growth is set to see the largest sustained rise in history matching the huge expansion seen in Saudi Arabia in the 1960s and 1970s”


And as a topic for another day gas is becoming so cheap that for bulk energy it will take market share off oil eventually. There is growth in offshore as Brazil and the GoM show:

Brazilian production forecast.JPG

There might well be another bull market in oil… but whether it leads to one for rig and vessel companies is altogether a different question? There will be profitable companies in offshore they will be just look, and in some cases be, different from those in 2013/2014.

There is an interesting parallel in shale infratsructure to offshore infratsructure providers in investment terms:

That fate has just arrived for the pipes and plants connected to some of the first great shale-gas plays in Barnett, Woodford and Haynesville. In September, Wells Fargo analysts estimated that four pipelines serving the original boom areas would be re-contracted for much lower volumes. Recurring operating costs and lower prices create distressing leverage on those declines.

According to Wells: “We estimate the four pipelines will see a median tariff decrease of 39 per cent and ebitda [earnings before interest, tax, depreciation and amortisation] decreases of 66 per cent, once legacy contracts expire.”…

This is not the end of the world for the midstream business. Other, better informed sources of capital can replace MLP money. However, the oil and gas infrastructure bubble is over. An American Petroleum Institute study in 2017 estimated “pipeline and gathering capex” would decline from an annual average of $31.3bn in 2013-16 to $20.8bn in 2017-35.

That is still a lot of pipeline but the ongoing returns appear to be weighted in the E&P companies favour, not the infrastructure providers. Offshore investors probably have some sympathy for pipeline owners.

Any offshore reovery scenario needs to be realistic about how the “new demand” will play out on the current and future asset base. Demand will vary by region, asset class, and type of project at the margin, but an overall contraction in the supply side of the market is a certainty as US shale production continues to grow faster than overall oil demand.

Capital raising and marginal production…

A very good article in the Houston Chronicle outlines the scale of the capital being raised in the US to pour into shale and the related infrastructure:

Private equity firms have raised more than $200 billion in funds for energy investments since 2014, including $50 billion set aside for shale drillers, according to research firm IHS Markit. They have stakes in more than 350 privately held U.S. oil producers, including 73 companies launched last year with $12.4 billion in investments, according to research firm 1Derrick. Those investments came in about one-third higher than in 2016.

Private equity firms also were involved in $15 billion worth of oil-production transactions last year, three times more than from 2008 to 2012. They were party to 15 of the 20 biggest deals last year. Now, roughly 40 percent of the 979 rigs drilling across the continental United States are tied to private equity-backed companies, investors said…

In Houston, 20 local private equity firms have raised a combined $56.3 billion in funds over the past decade, most of it meant for the oil industry, according to Preqin, a company that collects data on alternative investment industry. A portion has been set aside for investments in the health care, manufacturing and other industries.

In contrast, and not strictly a fair one, last week Chariot Oil and Gas, a small London offshore explorer listed on the Alternative Investment Market (“AIM”), announced the final stages of a capital raising, having raised USD 15m earlier in February the follow on issue seeking €5m got only 41% acceptance. Chariot looks to be a well run company, focused on Atlantic frontier exploration, but the sentiment is simply not there in the equity market to back these offshore exploration companies at the moment. I think that this is one of the few capital raises on the whole of the London Stock Exchange for oil and gas companies in 2018. The money just isn’t there.

The London AIM market has always been a good proxy for the availability to fund marginal offshore developments. By virtue of history and the leading position taken by the UK and Norway in developing the offshore industry (Brazil would not have been possible without the pushing of the technical envelope that was achieved in the North Sea) there was a base of investors who understood, and would back, offshore projects.  EY used to publish an index of the Oil and Gas companies on AIM, the fact they have stopped  (2014) is a data point alone in how this source of funding is declining in importance. As a comparison in 2012 and 2013 here are the stats for capital raising in London:

LSE funds raised.png

Nearly all the capital was destined for riskier, more marginal, offshore projects: Cameroon, Nigeria, Senegal, Mozambique, and the UKCS amongst others. On the main board Premier Oil raised money for Falklands exploration and Enquest was riding high as investors felt the protracted process to get these marginal fields into production was worth the time as risk capital. It’s not just a billion of risk capital that has been withdrawn, it’s a reflection of a wider market sentiment of the difficulties faced in raising money for offshore projects.

And that is really the link: AIM used to fund marginal production, new risky exploration and development outside that which larger, and more cash rich, E&P companies would undertake. Now in the US that source of capital is being provided by PE companies (and high yield debt) which reflects both the potential geological opportunities available but also where the highest profit at the least risk can come from. And that capital isn’t backing offshore anymore it is backing shale. When the price of the underlying commodity is so volatile, and not on a seemingly unstoppable upward trend, then smaller bets in an industry with lower upfront costs and a lower risk payoff profile seems like a better place for money to go. For an industry as dependent on capital as offshore E&P is this is not a good macro indicator. Capital begets capital in a self-referencing cycle sometimes because it provides the illusion of liquidity and asset price appreciation for investors, the more private equity money that piles in, the easier an exit will be, so more private money piles in.

If you look at Enquest and Premier Oil, two major independent investors in the UKCS, they are struggling under enormous debt loads and have prioritised payments back to debt and equity holders over development activity. With Enquest bonds trading at ~88% of par, £1,9bn in debt, and only £344m of equity, it is easy to see why: lenders and shareholders want their money back not worry about IEA predictions of impending supply shortages. It is worth noting in Jan 2017 when Enquest took over the Magnus field from BP that BP had to lend them the money, one can assume as both parties knew that external funding, even for such a good strategic deal at only £75m,  was unavailable. Shareholders in these companies don’t feel rich they feel like they might not lose everything:

Enquest Bonds over 1 Year (hardly investment grade as of 28/03/18 and as recently as Sep 17 pricing in  default effectively):

Enquest bonds.png

Enquest Share Price over 5 Years (as at 20/03/18):

Enquest Share Price 5 Year.png

If you are a shareholder in Enquest the current oil price doesn’t make you want to go mad on increasing production it just gives you comfort you might get your money back. Enquest is a leveraged bet on an increase in the oil price no matter how well run. This is emblamatic to me that even today some people talk about an increase in offshore spending as if it is a given as the oil price improves, but no one can actually explain in a logical fashion where the money is coming from? Or how companies like Enquest could actually afford to spend more? Increased offshore spending isn’t simply a linear function of an increased oil price it requires a change in capital market conditions as well.

The UK is a marginal development region meaning it needs higher prices to sustain E&P: $60 – 70 oil keeps the lights on and the administrator away, it isn’t a money making machine.  When credible forecasts come in that the oil price could drop as low as $51 in 2018 shareholders are pressing oil companies to lower CapEx and not rush into projects. Enquest also won’t be turning on the maintenance spend more than needed in this environment as a relatively small price decline would cause it real issues given the high fixed cost base and finance commitments. If anything it needs to build some financial latency if it can.

Coincidentally I came across this amazing video of the Ithaca Energy’s Stella development (it really shows off the scale of the development and the capital commitments). Ithaca both an AIM and UKCS success story, recently sold to the Israeli energy company Delek, for less than some of its longer term investors were happy about. Historically using the AIM market Ithaca was able to raise sufficient capital over a number of years to increase in size and gradually develop ever more complex and sizeable developments. You couldn’t repeat that trick now as the money and market sentiment isn’t there.

Ithaca also highlights that investors in these companies were hoping not just for the business to work but also for a takeover premium when the company got to a certain size. A bid in the form of a takeover often carried >25% takeover premium. Investors wanted not just exploration and production success but also dreamed of the next Cove Energy. Cove raised money on AIM over time at an ever increasing premium:

  • June 2009: £4 million at £0.12 per share
  • September 2009: £42 million at £0.20 per share
  • March 2010: £26 million at £0.40 per share
  • November 2010: £110 million at £0.76 per share…

… And then attracted a bidding war that Shell eventually won (at a 70% premium to the undisturbed share price). Everyone got rich. Whereas Ithaca, a great and successful company, showed how remote chances are for a massive takeover battle for an offshore-based production company are. Again as a contrast takeover activity in the US Shale sector is booming, last week Concho Resources paid a 15% premium to access RSP Permian (an $8bn equity acquisition).

Yes, private equity has made significant investments in the UKCS, but these are essentially deals that allowed others to exit. Chrysoar, Siccar Point, and Ineos were all mainly exit deals for someone else. All the purchasers have a significantly higher cost of capital than the sellers and must surely rely on some profit on exit to make the economics work? As private equity companies prefer to use leverage they will also face a constraint on how much cash flow from operations they risk on development spending as the price of oil fluctuates.  Their debt commitments are fixed and they have less to spend on development if prices do not rise.

News that Siccar Point is looking to offload half it’s stake in Rosebank to reduce CapEx commitments show the feeling of their shareholders (Blackstone with $7bn in energy portfolio investments and Blue Water Energy) regarding UKCS developments and their likelihood of recovering this with increased oil prices (although both are going long in Norway with Mime). I see this news as a real marker for a change in investment sentiment in the PE community for investment in offshore. The longer the oil price stays range bound at current levels, and forecasts come in for the downside, expect PE investors to be far more nervous about offshore CapEx commitments than industry companies. The constant focus on delaying Rosebank until costs have been driven down to an acceptable level show that while the supply chain may get some utilisation from this project they are unlikely to make money from it.

The statistics point to the UKCS entering a period of massive investment decline, larger than relative to the rest of offshore, that will be very hard to reverse, and the AIM/London Stock Exchange reflects not a lack of potential projects but a lack of willingness to invest in a sector with such long-term and risky structural characteristics.

I think there are two factors that are really important for the UKCS:

  1. The payback time for offshore projects is significantly longer and more complex than for shale projects: see the decision tree at the top of this article. The cost of a well for shale is ~USD 10-12m and the payback, although lower, can start to come in months (this is true globally as well obviously).
  2. Tax: one of the reasons the Norwegian shelf has held up better compared to the UK is that you get a cash reimbursement of 78% of actual drilling costs from the tax authorities, this is consistent with loss aversion theory which recognises that people prefer to avoid losing money than acquire an equivalent gain. The UK fiscal regime takes less but you have to find oil first at a significantly greater risk weighted loss ratio.

For the wider offshore community I guess given the size of the funds being raised in Houston that people will end up trying to raise funds there more than London. In that way new offshore projects will end up being evaluated side-by-side with shale projects, some investors may like the diversification element. But the trend for offshore to be focused on fewer “mega projects”, dominated by cash rich larger companies that can afford the financial and technical risks, seems to be locked-in for as long as capital markets remain in their current state. It’s not the end of offshore it’s just a different offshore, particularly at the margin.

For the offshore supply chain in general any recovery story that is credible needs to explain where the capital is coming from to fund projects. Because without the capital there clearly won’t be an increase in project demand and the Demand Fairy will fail to appear (again).  For an industry too long on supply that is where the adjustment will be made.

What gets measured gets managed…

Chevron and BP released data this week highlighting their continuing focus on reducing production costs and productivity improvements. To set the tone in their Annual Report for 2017 for BP made this comment to the above graph:

Dated Brent crude oil prices averaged $54.19 per barrel in 2017 – the first annual increase since 2012 but roughly half the average of over $110 seen in 2011-13.

Which just goes to show that while the offshore industry is using an oil price USD 60-70 to show increasing confidence it may not feel like that to an E&P company who spent billions on projects with significantly higher price assumptions a few years ago:

BP Upstream 2017.png


This Chevron slide highlights why the Demand Fairy hasn’t appeared in  offshore despite a rise in prices:

Chevron category cost reductions.png

Spending on Subsea at Cheron is down nearly 70% since 2014! This is an absolute number so the fact that Chevron have completed some major projects influences this, but it also doesn’t change the fact of the scale downwards in subsea spending that a ‘Super Major’ has managed to make in a very short space of time. That drop in production costs comes solely from doing stuff internally cheaper but in reality by procuring from the supply chain at ever cheaper rates.

BP has also dropped its production costs significantly:

BP Unit production costs 2017.png

The blue “REM” by the way means the remuneration committee looks at this before allocating senior manager pay. In other words senior managers have a great deal of economic interest in ensuring this gets lowered constantly, as the dictum goes “what gets measured gets managed”. Interestingly in 2013 this wasn’t a metric, then it was all about operating cash flow and delivering production targets and projects. Now saving a few thousand a day on a rig or vessel, going offshore for less days, doing more work onshore if possible, all these will be looked at with a degree of rigour unknown in past times. This is a new and constant trend in the offshore industry and I doubt it will ever go away now.

The continuing impact of this for those involved in offshore is clear: there will be a relentless focus, despite an easing of spend for offshore, on driving costs down. These targets will be filtered down the organisation through objectives and goals to other managers who will be bonused against cost reductions. Pushing the supply chain to lower costs will be measured and therefore managed: the clear implication in a period of oversupply is continuing margin pressure.

The argument that offshore spending will have to increase as the Reserve Replacement Ratio is dropping is starting to look tenditious as well:

Chevron resources.png

Clearly it’s all about the shale at Chevron, but BP was fine as well:

BP RRR 2017

Chevron is making clear where future investment will go:

  1. Deepwater US

Deepwater US.png

2) Shale in the Permian (note the comments re: “factory” something I have discussed here before)


While BP is also making clear that offshore is important but will only be part of its investment in projects:

BP project mix 2021

Two companies doesn’t make an industry, but these were, and remain, significant investors in the offshore space. But it is clear they have changed in a structural way how much they will invest in offshore, and how the invest in offshore, and the amounts are significant to the offshore industry supply chain as a whole (especially as they don’t seem to be anomolies).

When I look at data like this,l and see business plans that rely solely on an “inflection point” in demand, or waiting it out for “the recovery”, I don’t think they are reflecting likely scenarios now. A base case for offshore is surely one without a dramatic change in demand conditions? The implications for many business models in the offshore space from that are profound nearly four years after the price decline began.



Shale productivity and operating costs…

Some interesting data from the Dallas Federal Reserve Dallas Federal Reserve:

Dallas Fed Q2.png

I get the survey methodology isn’t perfect, but it’s a good indication. The trend on cost is interesting, down on 2016 but up on 2017 as cost pressures rise despite productivity improvements.

Look at the required operating costs:

Dallas Fed Q1.png

A slight rise since last year but comfortably below the spot price. The US has shown that financing costs are important, but ultimately given a downturn these producers will find capital provided they can produce above the marginal operating cost per barrel.

Cost pressures are on the rise as capacity constraints become clear. But this is an industry operating comfortably within in its cost and profitability constraints at current price levels.

A journey in graphs and capital intensity…

The above graph was taken from a JP Morgan report into the oil price this week. I wouldn’t read too much into the headline, as I have said before in the short-term I think the oil price is a random walk, but it gives you an idea of what a well researched analysis thinks the long term breakeven price is in the 50s. That isn’t my view but it reminded me of this graph from 2013:

Berenberg 2013.png

This is from a report in 2013 that Berenberg Bank published (using Infield as their source). Rystad had a similar one in 2013 (the article is very perceptive in retrospect):

Rystad 2013

The key for me is how far shale has dropped down the cost curve and the fact that this has been driven by productivity improvements while utilisation in the industry has been high (i.e. cost pressure was on the upside not the downside). I would argue a majority of the decrease in offshore costs has come about through over capacity and economic value (debt and equity) being wiped out. Given that many offshore assets are designed for 25 years of operational life this is a real issue.

I was interested to see the Noble/GE link this week with the aim of reducing drilling timing by c. 20%. But surely this points to the future where more planning and onshore data work will lead to less offshore execution time? I thought this was cool:

The Digital Rig solution combines data models from a digital replica of physical assets, known as a digital twin, along with advanced analytics to detect off-standard behavior, providing an early warning to operators to mitigate a problem before it strikes. Thanks to vessel-wide intelligence, personnel both on the vessel or onshore can gain a holistic view of an entire vessel’s health state and the real-time performance of each piece of equipment onboard.

Offshore is going to have to work out how to increase productivity to keep winning projects but a common theme is the need for less capital intensity:

Chevron Corp. is studding the ocean floor with heavy-duty pumping gear as part of an effort to make deepwater oil discoveries competitive with shale.

The idea is to force crude from newly drilled wells in the deepest parts of the Gulf of Mexico to flow through miles and miles of pipe to platforms built a decade or more ago, said Jay Johnson, Chevron’s executive vice president for upstream. By lopping off the billions it would cost to construct each new platform, offshore exploration begins to make economic sense again.

That methodology will use a lot less asset time than a traditional tie-back/FPSO or trunkline solution I am sure. A realistic view of the next offshore cycle requires a recalibration of many mental models I feel.