OilVoice Magazine | February 2015

Edition Thirty Five – February 2015

Oil price view for 2015 Free is the Way! Oil and the global asset crunch

Adam Marmaras Manager, Technical Director Issue 35 – February 2015

OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 207 993 5991 Email: press@oilvoice.com Advertising/Sponsorship Mark Phillips Email: mark@oilvoice.com Tel: +44 207 993 5991 Social Network Facebook Twitter

Hello and welcome to the 35th edition of the OilVoice Magazine.

2015 is set to be a year like no other for OilVoice. For starters, we have completely redesigned the site from the ground up. This was to service our growing user base of mobile and tablet users. The new design is responsive which means it works beautifully on all devices. A mammoth task, but well worth the end result.

We have also introduced training to OilVoice - which we took over from our sister company Finding Petroleum. We're lucky to have some of the best trainers in the business working for us. Take a look at our upcoming courses.

Google+ Linked In Read on your iPad You can open PDF documents, such as a PDF attached to an email, with iBooks.

This month is another great edition of the magazine. We received a lot of excellent content in January, and I’m sure you’ll enjoy reading it.

Hope you have a prosperous 2015!

Adam Marmaras Managing Director OilVoice

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Table of Contents Tech Talk - Projections 2

by David Summers

2

Hey Bo Didley, do you know this RIF?

by David Bamford

5

Whither Oil Prices?

by Stephen A. Brown

7

Bernstein Energy: up or down? An oil price view for 2015 highlights

by Oswald Clint

11

Free is the Way!

by David Bamford

13

Oil price volatility - take the long term view and ride out the storm 15

by Henry Hawkins Here for Deeper Knowledge

by David Bamford

17

Must do better, can do better!!

by David Bamford

19

Oil and the global asset crunch

by Andrew McKillop

21

European Oil & Gas 2015: why the majors remain attractive highlights

by Oswald Clint

25

Where to do better!

by David Bamford

27

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Tech Talk - Projections 2 Written by David Summers from Bit Tooth Energy It is the end of another year, or more optimistically the start of a new one. Last year I was tempted to make a couple of predictions for the future. And while I can make the case that they were not too wrong, they did not include the drop in oil prices, which has now taken the price of our local gas to below $1.85 a gallon. China has, in recent months, seemed less belligerent about claiming large sections of the China Seas. Whether this has anything to do with the relative success of rigs that have drilled in those waters is something that still remains an unknown.

But it is the changing price of gasoline, itself reflective of the drop in oil prices that is the big news. WTI closed at $53.56 today, and Brent at $57.50 a barrel. Predictions include some who would suggest that the price will continue to fall, until it reaches $20 a barrel, and there it may stay for some time. Well it certainly grabs a headline, but that is about all the value that particular forecast contains. The futures prices suggest that the price has yet to bottom out, though it may be getting close to that value.

Figure 1. Crude oil futures prices (EIA TWIP) None of the recent news suggests that there will be a further increase in supply to sustain the current imbalance between available supply and demand. Libya is descending even further into a mess, with the oil facilities at the port of Es Sider now being destroyed.

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The likelihood of significant increases in production and the return to export levels achieved earlier this summer seems increasingly nonexistent. Neither Russia nor Saudi Arabia are likely to increase production, although the latter are continuing to produce the increased volume that they originally put on the market to replace Libyan losses. And so this leaves Iraq and the United States as the key producers who can significantly change the current supply:demand balance in any significant way.

It is probable that, with the agreement between the Kurds and the Central Government now having generated a second payment of $500 million to the KRG that the agreement may be sustained and grow. At present the Kurds are to supply about 550 kbd, of which 300 kbd will travel through the new pipeline to Turkey and thence onto the world market. The rest will be supplied to Baghdad. Meanwhile production in the south (which gets exported through Basra) has seen some increase.

Whether the Kurdish production can increase to over 1 mbd by the end of next year remains open to some doubt, given the ongoing conflict, and the target 6 mbd by the end of the decade for the entire country will likely require changes that the current conflict, which shows no signs of ending, will inhibit.

One of my responses, when the drop in price first started, was to note that the oil supply system has a certain inertia to it. And here I am not talking about the fluctuations in price that one sees in the stock market, and in the price of the crude, but rather in the time that it takes to stop current drilling, postpone future plans and to reduce the production from existing and new developments.

Thus the drop in investment in new production, whether in Russia, Iraq or the United States takes some time to have an impact. Unfortunately for those expecting the price to continue to fall, in the face of the overabundant supply, the situation has changed since historic times, where well production was relatively stable and the oversupply situation was corrected by shutting in production (mainly by Saudi Arabia). Even then it was the perception of the response that drove price rebounds, rather than the immediate reality of the changes.

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The system this time is different. The increase in production in the United States has been sustained, and over the last two years has produced more than 2 mbd more than at the start of that period.

Figure 2. US crude oil production over the past two years. (EIA TWIP) The rig count in North Dakota has already fallen to 170 rigs compared with 187 at this time last year. Concern about the oil price has led companies to cut their investment plans for next years, in some case by 20% so that the rig count is likely to continue to fall. And with the short life at high production values for most wells that will soon affect production. The North Dakota Oil and Gas Division of DMR shows the consequences of this:

Figure 3. Future production estimates from the ND DMR Oil and Gas Division.

The blue line requires about 225 rigs in continuous action, so that won’t happen. By the same token the black line is with no more drilling, and that won’t happen either.

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The result will be somewhere in between, probably moving the peak out beyond the current projection, but also lowering it as the existing baseline drops with less wells significantly contributing. (Bear in mind it is taking 11,892 wells to sustain current production levels.) But in the short term the line will likely dip down until the price rebounds.

The question now becomes how soon that drop in US production will become evident, and have some impact. I doubt that it will be before June of 2015.

On which note may I wish all readers a Happy, Healthy, Successful and Prosperous 2015.

View more quality content from Bit Tooth Energy

Hey Bo Didley, do you know this RIF? Written by David Bamford from PetroMall "Those who fail to learn from history are doomed to repeat it." -Sir Winston Churchill Once again, there is a lot of excited chatter about cost cutting in our industry.

Oftentimes in the past, this has meant cutting great swathes of people (also known in better times as 'our most valuable resource') out of the team. Of course now it's happening again - RIFs are in progress at, for example, Schlumberger and Genel Energy to highlight just two.

Here's something to think about: perhaps the only person you can trust to manage your career to your expectations is yourself, unless companies change their behaviour significantly!

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A brief history of RIF-ing So what is a RIF? Please note I am not talking about a riff which I understand in music is a repeated chord progression, pattern, or melody, often played by rhythmic instruments.

No, I am talking about the tendency of folk in our industry (let's blame HR, it's easier that way!) to hide redundancies under a veneer of verbiage.

After all, 'job cuts' is too blatant and incomplete, 'manpower reductions' only slightly less so: so we get to terminology like 'rightsizing the organisation' and my favourite (which I learnt in the USA in the mid-1980's) which is 'RIF-ing'. RIF = Reduction in Force, you see.

And it was accompanied by such delights as folks' swipe cards not functioning when they arrived at work; Town Hall meetings in which everybody received an envelope on arrival, to be opened on command, those with a green slip being told to return to their desks etc etc.

All this was the part of the cost cutting wave of the second half of the 1980's; there was another one in the second half of the 1990's. The latter especially 'benefitted' from the synergies available from the various mergers of the time.

With the extreme benefit of hindsight, we can see that this bloodletting has had two profound effects on our industry, driven by the fact that:  

Many experienced people were let go.

Graduate recruitment dried up to a trickle.

By 2005+, when our industry was back in better times, the realisation had dawned that this RIF-ing had resulted in: 1. An 'underweight' generation of folk approaching 50, who were going to retire fairly soon, taking their knowledge with them. This was sometimes referred to as 'The Great Crew Change' 2. A real shortfall in the absolute number of petrotechnical staff available to fill the mushrooming number of jobs. CERA foresaw a 10% global shortage by 2010.

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There was some wailing and gnashing of teeth, with various industry luminaries going so far as to blame the shortage of decent staff for the widespread failure of development projects to be delivered on time (though our Finding Petroleum Forums have revealed that there is in fact a different root cause). This presentation is a good example of the genre.

So as oil prices rose - with optimistic forecasts of their remaining permanently above $100/barrel, perhaps even reaching $200 - the industry set about hiring, hiring, hiring and you could read of this sort of thing!

In view of the history and precedents of the last 30 years in our industry, you would be perhaps unwise to manage your career by taking too much notice of what companies say at high price times and rely on managing your own career!

View more quality content from PetroMall

Whither Oil Prices?

Written by Stephen A. Brown from The Steam Oil Production Company Ltd The recent collapse in oil prices has taken pundits and oil producers by surprise. It was only six months ago that prices were over $100/bbl and at that time they had been above $100/bbl for three and a half years. In fact the stability had become uncanny, so perhaps we should have seen the collapse coming. I would like to claim I had been prescient but sadly I wasn't.

There are lots of conspiracy theories on offer, but it seems to me the root of Saudi Arabia's refusal to defend the oil price lies in its fear of a repetition of the loss of market share that OPEC suffered in the early eighties. But there are good reasons why the 2010's are not the 1980's.

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I like to analyse the numbers, therein lies the explanation for OPEC and more particularly Saudi Arabia's stance. Lets look back to the early eighties and see what happened to OPEC's market share after the oil price shocks of the seventies.

Oil prices since 1965, in 2015 dollars with both total world oil supply and OPEC market share capacity up until 1990 shown in the background.

OPEC hiked prices twice in the seventies; the first jump in prices slowed down the growth in oil consumption and OPEC's market share slowly eroded, but the move was essentially a triumph for the organisation. Their revenue tripled and while their exports were no longer growing that was a small price to pay.

The second jump in the oil price did not turn out so well for OPEC; this time their market share was not just eroded, it collapsed; and on top of that ignominy global consumption fell for four years in succession. By 1984 OPEC's market share had dipped below 30%. The organisation went from being the masters of the oil market to its victims. By the end of the eighties the price was back down to $30/bbl (in 2015 money) and oil companies everywhere had embarked on the endless rounds of redundancies, rationalisations, mergers and cutbacks that has characterised the industry ever since.

It took until 1996 before OPEC's could regain a market share of more than 40%.

OPEC, and the Saudi's in particular, learned the lesson that you can price yourself

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out of the market. High oil prices encourage energy savings and unconventional production techniques. If you charge too much for your product buyers find alternatives and other smart people find new ways to take your market share away. It is easy to lose your customers and damned hard work to get them back.

So what has happened recently?

Well it took a long time, but eventually world oil demand grew to the point where OPEC no longer had a lot of spare capacity unused. It seems pretty obvious now that we can actually chart all the data, but once OPEC spare capacity fell to around 2% of world oil consumption, the oil price was on a hair trigger. From 2004 onwards the price marched upwards, breaching $100/bbl with ease and briefly touching $147/bbl (in 2008 money) before that high price tipped the world into recession.

The ascent in prices wasn't really OPEC's work, speculators and traders got the blame, but the oil producers basked in the revenues and the pundits and bankers predicted ever higher prices. But as the saying goes "what goes up must come down" and, just as it has done recently, the oil price collapsed at an alarming pace.

That price collapse, along with a massive injection of cash in the euphemistically labelled "Quantitative Easing Programme", took the nasty edge off the 2008 recession and it wasn't long before oil consumption restarted its modest march upwards. Prices recovered from their lows, and OPEC was once again able to

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rebuild its market share. But what is really interesting is that this time round OPEC was able to increase its market share, while the oil price averaged $80/bbl. There was no need to endure a prolonged period of $30/bbl oil to recover the ground lost in the price exuberance of 2008.

So it turns out that the early years of the twenty-first century are indeed different from the eighties. In the eighties $100/bbl oil destroyed OPEC's market share; $40/bbl to $60/bbl oil eroded OPEC's share and it took prices as low as $20/bbl to $30/bbl to grow OPEC's market share. Nowadays, $100/bbl to $120/bbl oil slowly erodes OPEC market share, and OPEC can grow exports and market share with an oil price of $80/bbl oil. Why? Well, "Peak Oil" might be an unfashionable theory but the world is slowly marching up the supply cost curve.

The futures market sees this too. Two years ago when the oil price was $115/bbl the futures market predicted that the price would correct back to $90/bbl. Last Monday with Brent trading at $51/bbl the futures market thought that the price will correct back to $77/bbl.

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So what is an oil producer to do? Well, for sure the stability of the past few years has gone, the notion that oil would stay steady at $100/bbl for a long time was tempting, but only a chimera. For what its worth, it seems to me, that a sensible oilman or wise oil investor can plan for $80/bbl prices, they might hope for $100/bbl prices and for prudence they should stress test their projects, business and investments at $60/bbl, but $80/bbl seems the price that we will oscillate around for some time to come.

For traders I have no advice, the price tomorrow could go down just as easily as it could rise, but the longer the price stays below $60/bbl the more dramatically the price will spike when events eventually turn the tide.

View more quality content from The Steam Oil Production Company Ltd

Bernstein Energy: up or down? An oil price view for 2015 highlights Written by Oswald Clint from Sanford Bernstein In 2014 we had the strongest non-OPEC supply in over 30 years followed by one of the largest intra-year (negative) demand revisions (Europe, Russia, Ukraine, Syria, Iraq, Japan). We also had the warmest weather on record across Europe, the second lowest Chinese oil demand since 1990, and an unusual OPEC decision not seen for 30 years (1986). A 50% price correction ensued from this string of unusual events. We've updated our supply and demand model to help form a view on prices from here.

Global Oil Demand should rise by at least 1Mbpd in 2015 up from a weak 0.7Mbpd in 2014.

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GDP is the greatest cyclical driver of oil demand growth and set to accelerate, from 3.3% in 2014 to 3.8% in 2015. In our models we forecast oil demand as a product of population growth, GDP per capita growth and long-term average oil intensity; hence this year's global oil demand growth should exceed last year's (all non-OECD).

Structurally, the world's oil intensity (i.e., oil consumption per $1000 of GDP) has been declining at a 2.4% 10-year CAGR, and the 2014 average was in line at 2.3%.

Non-OPEC supply should rise by 0.9Mbpd in 2015 down from the 1.9Mbpd in 2014.

Last year's non-OPEC supply was monumental as it was the highest in 30 years and the first time growth was greater than 1.5Mbpd. Within this 1.47Mbpd was US. In 2015, the main sources of supply in our model are the US (0.6Mbpd) and Brazil (0.3Mbpd) as other regions net out to zero. Downside surprise to non-OPEC supply is more likely in 2015 due to the impending 20-30% capex reductions we expect.

IOC's had already deferred $300Bn of capex and 2Mbpd of future oil production during 2013 and 2014.

Increases in global spare capacity have added additional price concerns.

Specifically, spare capacity rose to 3.2Mbpd in 2014 up from 3.1Mbpd in 2013 but reached 3.45Mbpd by November. If we look back over the last 45 years, then spare capacity remains low at 4.4% of global demand in 2014 including ineffective spare capacity. Only in the demand surprise period of 2004-2008 did it average lower around 3%. Up to 2004 and throughout the 1990's it was 6%, and 14% on average before the 1990's. For the next five years our model suggests 4-5% which means prices should be at marginal cost.

Increases in global inventories in the short term could dampen price recovery until mid-2015.

We expect supply reductions from the impending 2015 capex collapse though have not yet factored them into our estimates. While they may take 6-12 months to filter through, our quarterly global supply and demand balances suggest inventory building in 1H 2015, which could prevent rapid price recovery until mid-2015. As demand and supply are revised positively and negatively (respectively) through

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2015, we wouldn't expect the inventory builds to continue into 2H 2015.

Updating oil price estimates and still seeing undeniable upside for long term investors.

Rolling forward from the 2014 supply strength, lower than expected demand together with spare capacity and inventory increases, we cut our Brent forecasts to $80/bbl (from $104/bbl) in 2015 and $90/bbl (from $109/bbl) in 2016. Our estimates are 5% ahead of consensus in both years and 13% ahead over the medium term, while falling substantially ahead of the forward curve (30% on average in 2015 and 2016).

View more quality content from Sanford Bernstein

Free is the Way! Written by David Bamford from PetroMall

To everybody who went to the 2014 EAGE in Amsterdam, I hope you enjoyed yourselves, especially considering how much it cost you and your company: So, you took what, 4 days away from the office? Call that a week and let's divide the typical built up cost of a FTE of 200-250,000 Euros (do we still have them?) by 50 to get a cost of 4-5,000 plus your hotel and travel - hmm, another 1000 at least - plus registration, somewhere between 500 and 750 depending on your timing. So let's agree on ~ â‚Ź7000 in total?

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Of course if your company wanted to exhibit; well, my brain isn't agile enough to work it all out but I did hear that one well-known oil field services contractor figured that all-up it was going to spend ~$800,000 on the EAGE in Barcelona, and decided to give it a miss!

And, apart from having a 'good time', what do you expect to get out of it that you couldn't find by browsing companies' web-sites where all their papers, products and services appear anyway, and for free?

For example, most seismic companies do a really good job of showing you their multi-client data on their website.

You can browse all of this in an hour or so, and you don't have to go to any of those unnecessary parties or eat any 'cake'……..

Before I go any further, I should say that I don't mean this as an attack on the EAGE, or the SPE or the AAPG or the SEG. It's just that some things' time has passed…….

There are plenty of other entities, noticeably commercial companies, that charge amounts getting well into four figures - in €, £ or $ - to attend one of their events. Of course there are some that CEOs and CFOs go to that cost big wedges of money……….but that's OK? Or maybe not!

My point is, to repeat: We are increasing living in a world where you can download more or less anything, certainly more or less anything that conference presenters and exhibitors are willing to stand up and talk about and put on a slide, for free, more or less instantly - well, if you have decent broadband that is. And from the comfort of your own desk or study at home - without having to fight your way through LHR, ABZ or IAH! As the author of this article in the Telegraph pointed out 'All sorts of things we used to pay large sums of money for are now nearly or completely free.'

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So if you are thinking of going to the 2015 EAGE in Madrid, here's a simple question: WHY? And if you agree you shouldn't go when the oil price is less than $60 a barrel, why would you go when it's $120?

View more quality content from PetroMall

Oil price volatility take the long term view and ride out the storm Written by Henry Hawkins from Palantir The press suggests that oil companies are cancelling field development projects in the current low price environment. This made me question these decisions since oil companies should be long-term thinkers. Cash flow constraints aside, are they really making decisions based on 45 $/bbl oil?

Much is made of the volatility of oil prices. One of the great challenges of oil and gas companies is managing the uncertainty around future oil prices when making investment decisions. Indeed, 2014 has been a prime example with major indices such as Brent and WTI tumbling from 110 $/bbl down to 45 $/bbl recently. Many projects are simply not viable at such prices and this affects investment decisions. In addition it can lead to project termination of late-life projects, even if they might remain viable at slightly higher prices.

How do oil companies make decisions about viability and how do they select a longterm price forecast? The truth is that most companies take a slightly simplistic

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approach which is very heavily oriented towards using the current prices with bands either side. Many argue that they are notoriously bad at even considering extreme price events. The truth is that 9 $/bbl and 180 $/bbl are within the realms of possibility.

Certainly extreme price volatility affects the day-to-day operations of E&P companies. When prices are low, costs must be cut and it can be hard to gain approval for new fields. However, a typical field will produce for 20 years or more so really the investment decision should be based on a twenty year view of prices. In that context the month-on-month or year-on-year volatility is of little consequence.

Perhaps the secret is to take a long view and ride out the storm.

The graphic below shows West Texas Intermediate (WTI) from 1946 to the present.

It has been converted to 2014 real terms in order to present a trend that it is easier to interpret. The grey dotted line shows the monthly spot price with all the volatility. This could have been shown as daily prices which would have shown a little more volatility along with a few more extreme events. The orange curve shows a twenty year point-forward rolling average. There if a project had been sanctioned in 1985 it would have experienced an average price of 38 $/bbl over its producing life.

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Viewing this from the perspective of a life-time price paints a very different picture.

Perhaps E&P companies are not so flawed when they fail to consider the extremes.

This analysis does nothing to help answer the all-important question of what the forecast should be for 2015 and beyond, except perhaps to suggest that a long-term forecast of 45 $/bbl might be an extreme view.

View more quality content from Palantir

Here for Deeper Knowledge Written by David Bamford from PetroMall ‌ and Wider Opportunities?

If we do not act quickly, the UKCS and NOCS will soon be on 'life support' Naturally, first reactions have been 'Give us a Tax break!' and 'How do we get Costs way down?'

Yes, these are important because they finish up in the Numerator of the crude economic equation that describes profitability.

But there is also a Denominator which is, or are, barrels of oil or cubic feet of gas.

How do we input more of these into the equation?

I have two thoughts: Firstly, and beginning with a 'story'. Many years ago I had a minor role in BP's takeover of Britoil (previously of course BNOC, the government's national oil & gas company). This takeover was underpinned by profound understanding of North Sea OilVoice Magazine

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geology, of Yet-to-Find volumes, of undeveloped discoveries, of upcoming development projects, of producing fields. In point of fact, BP probably understood Britoil's acreage and fields better than Britoil did itself.

Today it is difficult, impossible actually, to see such a profound underpinning anywhere, perhaps because lots of key individuals have 'moved on', perhaps because of lazy assumptions that the North Sea's best days are somehow behind it.

And yet the significant Johan Sverdup discovery in the NOCS, in a well-explored area, was as I understand it, the result of deep geological knowledge and innovative thinking.

We know perfectly well how to do these things - see for example this summary of how work on Nova Scotia revitalised exploration there.

Something similar, of similar scope and imagination, is needed for the North Sea and, arguably, NW Europe as a whole. Somehow this has to be a 'multi-client' study, driven and delivered by oil & gas industry folk, not some academic or research exercise.

Secondly, we geoscientists have developed a lazy dependence on 'yet-anothertowed-streamer-3D-seismic-survey' which we need to move beyond. There are all sorts of new technologies 'out there' - from seismic nodes, passive seismic, fibre optics, full tensor gravimetry, electro-magnetics - that can tell us much more about the sub-surface, bringing better predictions, and higher volume successes.

Deeper knowledge and wider opportunities indeed!

View more quality content from PetroMall

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Must do better, can do better!!

Written by David Bamford from PetroMall Our industry finds itself at a bit of a watershed moment. No, not because of the oil price!!

We are perceived - by the owners of our companies, the shareholders - as having failed to deliver:



Exploration



Field Development Projects on time, on budget and as promised Reliable Reservoir Management IOR/EOR schemes as promised.

 

We need to up our game! We need to do better!

I believe that our problems stem mainly from our failure to perceive and describe more complex targets, more difficult reservoirs, properly. What is to be done?

Way back in the early 1990's, the twin 'disruptive' technologies of inexpensive 3D seismicand powerful interpretation workstations - the latter pioneered by Geoquest and Landmark - transformed the quality of our sub-surface insights. Hasn't little happened since then!

We need to move beyond the tired remedy of "yet-another-towed-streamer-3D seismic-survey", and start applying new "disruptive" technologies such as seismic nodes, fibre optics, non-seismic geophysics, permanent reservoir monitoring.

And then.....

Integrating, analysing, visualising and correctly interpreting these multimeasurements goes way beyond the 'lowest common denominator' desktop applications available today where the world of innovation has been replaced by 'one OilVoice Magazine

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size fits all'.

I have always believed that the best insights are found when everybody - for example, geologists, geophysicists, petrophysicists, reservoir engineers, commercial folk - are looking at the same thing, and working on the problem at hand as a team.

Working in an integrated way................................preferably looking at a big screen together.

On a lighter note‌‌.

Sometimes, maybe after too many mince pies and red wine, I mull over a collective name for the disciplines I just mentioned - in a way, we are always explorers but that strikes the wrong note, I think.....much too restrictive.

And then, watching The Bridge (Series 2), Lewis, Wallander, The Killing, Montalbano, Homicide Hunter.....you get the genre!!......, I realised that we are really detectives, taking scraps of evidence, all sorts of expert insights, and coming up with a story.

So, how about: Sub-surface Detectives!!

View more quality content from PetroMall

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Oil and the global asset crunch Written by Andrew McKillop from AMK CONSULT Canary in the Coalmine

Huge attention given by world media to the collapse of oil prices has diverted attention from similar falls in market prices for a range of other traded financial assets. These range from other commodities are called "bellwether" for their predictive role in major financial and economic change, such as copper. Others include the other base metals, food and non-food agrocommodities - and "pure financial" assets such as a range of national currencies, interest rate futures, government and corporate debt, and others. Often these "pure financial" assets are treated as if they were separate from the commodities, as two unrelated asset classes, but this is an illusion.

In some cases the existence of a “seamless asset space” is easy to prove. Starting with oil, the well-known ratio of "paper-to-physical" asset trading is itself a bellwether – using the ratio of futures contracts traded daily, versus the actual number of physical barrels of oil finally settled and cleared by futures trading. Taking some approximate figures, about 51 million barrels daily of the world's total 90 Mbd of oil production and consumption is market-priced and traded, but world total traded oil can exceed 5000 Mbd, for a 100-to-1 ratio of paper to physical oil. With oil-related derivatives creation and trading, the ratio climbs even higher. Although little remarked by the financial and other media covering the present and ongoing "oil price crisis", the crisis has created a probable long-term several-year trend of low prices and low-volatility of price, similar to the previous context of slow and small changes of high oil prices – in both cases resulting in less investor interest in "playing the market".

This tends to lock-in either high or low prices, after a period of major volatility, and provides us another bellwether. Using data from, for example, the US CFTC (Commodity Futures Trading Commission), the US "financial watchdog" for commodities trading, any major decline in daily purchases and trade of futures options will tend to indicate a lock-in of prices, whether they are high or low.

Conversely during periods of major volatility, speculators and traders will be more

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active, and will buy and play a larger number of futures and options contracts. Even the cost of buying and holding these options and related assets will weigh on the decision to abandon any speculative moves, such as “bear raids”on the daily price when volatility declines.

The Bigger Picture To be sure, oil is the single largest traded commodity - but all commodities only represent a small percentage of total traded financial assets. Commodities trading is dwarfed by equities, foreign exchange, national and corporate debt, interest rate futures and other non-commodity asset trading, by a very approximate multiple of about 8 to 1, and the ratio is tending to grow...

Separating the "hard and soft asset" classes is always difficult - as already mentioned we have the general class of assets termed "derivatives" which mix and mingle all kinds of tradable assets on a daily basis. What counts is that today's major macroeconomic trends - dominated by debt and deflation causing slow growth – can add derivatives proliferation to make it a "3D crisis". Any pullback of investor interest affecting these three factors will have a major knock-on to global, regional and national macroeconomic trends.

Taking oil as the “global macro” bellwether and ignoring the geopolitics (such as the need for high revenues from oil for Iraq to be able to fight ISIS), the price collapse can be explained as a "classic supply-demand" process, due to rising output featuring US shale oil and rising output by new small producers, especially in Africa, and what is politely termed "sluggish global demand".

This demand growth constraint on oil price recovery in fact hides a picture where major regions and countries featuring the OECD group (taking about 48% of global oil output), and particularly Europe, Japan and South Korea are continuing and deepening their energy transition away from oil. In some cases this is already a decadal or 10-year-long trend of annual declines in national oil demand. For the EU, Eurostat data shows decline trends, for some countries, that have continued from well before the year 2000. These pre-existing decline trends have been intensified by post-2008, post-crisis economic conditions. Similar long-term trends are almost certain for the US and Canada, although short-term economic recovery may raise demand on a few-years basis.

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Simple and basic energy economics, rather than ecology, lifestyle change, economic policy and structure changes featuring de-industrialization helps explain this longterm trend for oil, firstly bringing demand growth to zero, and then installing longterm decline, which on a worldwide basis using the metric of oil's role in primary energy, has been declining for 30 years! The energy economics of oil are negative, due to oil being overpriced relative to coal, and to natural gas in a growing number of regions and countries. In addition, in a growing number of "niches" the renewables can deliver cheaper energy than oil. Adding national energy security and environment policies, the negative long-term outlook for oil demand recovery is rather clear, even in the emerging and developing economies, starting with China and India, both of which have oil-saving policies and programs in place.

When we add the bigger financial-economic dimension of debt restructuring and reduction, which is a global problem and global necessity, we can see why the "bellwether commodities", including oil, are performing as they are!

The Post-2008 World Oil and energy economists are obliged by facts to accept that the so-called "short term correction" of prices on 2008-2009 when oil prices hit a low of around $40 a barrel was in fact the long-term trend towards lower prices for global oil pricing and natural gas prices in Europe and Asia, driven by major macroeconomic change.

Capacity growth in almost all domains and sectors - including global manufacturing, not just commodities - was phenomenal in the decade 1998-2008 following the bellwether Asian and Russian financial-economic crises.

Highly related to this, in the energy sector, the shorter-running asset spiral and decline in the renewable energy domain through the period of about 2005-2012 was a bellwether sub-sector crisis, including classic "boom-busts" such as global solar PV and wind turbine capacity growth, and the attempted lift-off for electric cars and vehicles.

Upstream of this we find what can be called the "general financial crisis", fundamentally based on debt, with a typical profile of fast growth and fast decline. To be sure, oil was a big winner for a long time, but past energy economic history shows us what can happen.

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The 1973-1986 oil boom, driven by an approximate 400% growth of oil prices in 1974-1981, was followed firstly by the 1986-1987 oil price crash, in which prices fell about two-thirds, and then followed by over 15 years of low or very low oil prices during whhich $18 a barrel was the “new normal”.

Whether or not this can happen again is certainly open to debate. Reasons why it might not happen, apart from geopolitical strains and pressures will surely include corporate debt restructuring which will be severe in the energy sector. Other factors that may “intensify the pain” of low oil prices will include national debt dilution by socalled “debt monetization or QE”, by competitive national currency devaluation, or by pure and simple debt abandonment, of course implying new and additional debt crises for a global financial-economic system that is still trying to work its way out of the 2008 crisis!

Arguments that for oil, this will shake-out high cost producers and speed oil price recovery also aided by cheap oil spurring oil demand - can be set against the experience of the previous 15-year trough in oil prices through 1987-2002. The 67% fall of oil prices in 1986-1987 was not followed by “instant price elastic recovery” of global oil demand. However, as in previous oil price crises and in general terms the present crisis, is a bellwether. How it is responded and reacted to will concern us all.

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European Oil & Gas 2015: why the majors remain attractive highlights Written by Oswald Clint from Sanford Bernstein 2014 was the roller coaster year for European Oil & Gas stocks.

Overall, the Oil & Gas sector swung 26% intra year from +11% at the end of June to -15% by year end. Against the European SXXP which climbed 4%, this left the energy sector worst relative performer. Across the individual sub-sectors then the European SuperMajors did best falling only 8%, then the Refiners -9%, Integrateds 14%, Services -30%, E&P's -31% and Russian's -38%.

In 2015, we still like the Majors and they remain our favourite positioning ahead of E&P's due to: 

More constructive oil supply & demand balance than 2014. While we didn't expect it, during 2014 the industry managed to add the most non-OPEC supply in over 30 years just as demand growth was cut in half from mid-year.

Our companion note today finds it difficult to envisage such a scenario in 2015 especially when industry capex will fall 20-30% and demand upside surprises are now more likely. Our $80/bbl 2015 and $90/bbl 2016 Brent estimates thereby offer earnings support.



LNG cashflows and increasing chance of further capacity reductions in European refining. Most of the Majors have material LNG portfolios which offer stable production and contracted sales reaching 10-30% of earnings.

Price floors in these contracts will mitigate against some of the recent Brent decline. In Downstream, capital rationing means less for Refining and more shuttering of underperforming European assets should be expected in 2015 while margins are up 100% as oil fell.



Twins drivers of volume growth and capex flattening off. Industry capex will fall >20% in 2015 but the Majors capex had already peaked in 2013. This

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hasn't changed and will drive FCF improvement. Volume growth should be strong in 2015 around 5% on average for the Majors and 13% including the Integrateds BG, GALP and Repsol. We had capex falling 5% naturally in 2015 but it will be more. 

Valuation remains attractive. The Majors PCF multiples expanded 25% by June 2014 on expectations of this better FCF sustainability. While the sector gave this back in 2H 2014 relative yields at 1.92x, which have only occurred once over the last 30 years, now appears to indicate dividend risk. We see dividends (6% yields) as safe and to be confirmed in the strategy days.

We have not changed our preference for Brazil exposure and therefore BG and Galp.

Both stocks still offer peer leading volume growth of 10% and 50% CAGR respectively to 2018. Both companies also moved forward with the Iara development last week. Brazil is volume growth but the Santos Basin barrels are also 24% net margin barrels versus 12% for peers. For BG, the start-up of QCLNG in Australia, also last week, marks the end of a major capex phase and a new long life volume project.

We have updated our earnings, cashflow and price target estimates for the oil price correction of 2H 2014 and our new Brent estimates.

Our 2015 Brent estimate of $80/bbl is now 23% lower than before. Hence our EPS estimates fall 23% on average leaving us 6% ahead of current consensus while our price targets fall 16% on average. We still see undeniable upside for long term investors.

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Where to do better!

Written by David Bamford from PetroMall One of the benefits of being involved in an events business such as Finding Petroleum is that I get to meet lots of people and hear the opinions of all sorts of folk in our industry - from Majors, Independents, Oilfield Service Companies, Consultants, Investors, Analysts, Journalists etc etc.

I thought it might be worthwhile laying out some of the things I have heard over the last 12 months; obviously the current oil price implosion has added some 'colour' and, in some cases, invective! I have already touched on some of these inputs in my article from earlier this week.

Today I am asking, where - and how - do we 'do better'?

'Performance' issues: First of all, we have to admit that we need to 'do better' because: 1. Exploration has been very unsuccessful over the last 2-3 years, both in success rate and in the discovery of 'giants'. This prompts two questions where should we explore and how should we explore? o

o

o

Can we find 'New Geographies' (see below), new provinces where 'giant' fields remain to be discovered?

Have we reached the 'end of the road' with regional towed streamer 3D as our main offshore exploration tool?

And how do explore efficiently and effectively onshore?

2. 'Reservoir Risk' is a key contributor to the failure of Development projects; too much uncertainty is carried beyond Appraisal and FEED into project design and execution. o Can any new technologies help reduce uncertainties?

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3. Poor understanding of reservoir dynamics has led to expensive Reservoir Management and unsatisfactory IOR/EOR projects. o

Can we improve our understanding of reservoir dynamics with 'richer' surveillance?

4. We have no control over oil or gas prices; can we get Costs (way) down? Is it time for CRITE (Cost Reduction In This Era)? o Are there new, better cost/barrel, development technologies? o Can Standardisation deliver 10's of % cost reductions? o What about Automation/Remote Control?

'Geography' issues: 5. Shouldn't Deep Water and the Arctic be avoided?

The former is too just expensive - both to explore and to develop - at any imminent oil price, given the outrageous costs of drilling. The latter has this problem too but also incorporates unmanageable environmental risk. o In general, onshore anywhere - for conventional and unconventional resources - looks like a better bet.

6. Are there 'New Geographies' with Cost-of-Supply advantages? o

Perhaps we should focus on Mexico which will open in 2015. Iran is a possibility but one that depends on the major political issues being resolved. Libya is probably not for just now, given the security situation.

7. Can we re-charge Mature Provinces? o

o

How do we re-invigorate the UKCS and NOCS; and much of South East Asia? Using some new 'disruptive' technologies perhaps. And driving Costs down, down, down‌‌..

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