OilVoice Magazine - May 2015

Edition Thirty Eight - May 2015

Oil Price Rally Built On Very Fragile Ground Have oil markets had enough of low prices?

Putting the Real Story of Energy and the Economy Together

SUPPORTING THE DEVELOPMENT OF NATURAL RESOURCES

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Adam Marmaras Manager, Technical Director Issue 38 – May 2015

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Hello, Welcome to the May edition of the OilVoice magazine. This month we have great content from Eoin Coyne, Gail Tverberg and Paul Hodges just to name a few.

The price of oil is slowly picking up, but not fast enough for many companies in our sector. We've had to respond to the downturn as well, and our jobs board is now free to use for recruiters. We'd rather see a busy and active jobs board, with all the extra traffic and members that that brings, than a handful of jobs and disappointed candidates. So if you're looking to hire or recruit, please take a look at our free to use jobs board. No catches, just hire!

Enjoy the magazine. If you have any suggestions on how we can improve it we'd love to hear.

See you next month!

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

Adam Marmaras Managing Director OilVoice

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Table of Contents Have oil markets had enough of low prices?

by Gary Hunt What's all this appraisal business then?

by Stephen A. Brown Deep Steam

by Stephen A. Brown OPEC hit as 'peak oil demand' arrives and US imports fall

by Paul Hodges Putting the Real Story of Energy and the Economy Together

by Gail Tverberg Oil Price Rally Built On Very Fragile Ground

by John Richardson How did that prediction work out, Nostradamus?

by Stephen A. Brown US jobs growth stalls as shale gas bubble ends

by Paul Hodges Q1 2015 Oil & Gas M&A tumbles to $7.1 billion in E&P sector

by Eoin Coyne What Iranian Supply Overhang?

by Stephen A. Brown

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2 5 11 15 18 23 27 29 31 36

Have oil markets had enough of low prices?

Written by Gary Hunt from Tech & Creative Labs LLC

Source: US EIA There is an interesting convergence in views by the global agencies that track oil supply and demand suggesting that US oil production is finally trending down in two of the biggest onshore tight oil plays at Bakken and Eagle Ford while global oil demand seems to be creeping up. The question is will this leveling off of US oil production growth be enough to bring world oil prices to more sustainable higher levels?

US EIA started it in its Annual Energy Outlook forecasting total US crude-oil production would be down by 57,000 barrels per day in May 2015. In Paris the IEA told markets to expect flattening. And even OPEC projected U.S. oil would peak at 13.65 million barrels a day in the second quarter of 2015 and then trend down in the second half of the year.

While OPEC has complained that the growth in oil production outside of OPEC was 2

the cause of the glut, Reuters reported the cartel itself increased production levels 810,000 barrels a day above its own self-imposed targets of 30 million barrels a day compared to 29.3 million barrels a day of expected demand for OPEC oil in 2015.

This suggests that OPEC itself is responsible for about 1.5 million barrels a day or 54% of the estimated 2.78 million barrels a day in excess oil supply for the first half of 2015.

'The US shale revolution has clearly been a game changer nearly doubling US oil production since 2008 and turning the US into the world's largest producer of oil and natural gas. As you can imagine, this terrifies OPEC and other competing producing regions. Why? Since 2008 total US oil and gas production has gone up 11 quads (quadrillion British thermal units) compared to Russian growth of 3 quads and Saudi Arabia production of 4 quads. Fear that the US shale revolution would contagiously spread around the world combined with the stark economic reality for the Saudi's that if they cut production to bring oil prices back up (as they have traditionally done) others would simply take Saudi market share. Enough—-was the Saudi conclusion.'

So Saudi-lead OPEC refused to reduce production levels in order to prop up oil prices. In a meeting of OPEC members in November 2014, the Saudi's said they were not prepared to lose market share by cutting their own production while others both inside and outside of OPEC kept producing more and more oil creating a glut.

Since then many have pointed fingers in this game of oil supply and demand chicken. The Saudi's blame the growth in US onshore production from tight oil—the shale revolution—for the glut, but Russia and other OPEC and non-OPEC members heavily dependent upon oil revenues for their budget have produced as if their lives depended upon it—which it does thus we have a world oil glut of more supply than demand given current economic conditions of weakening demand in China, EU and even the US. In fairness, without action by some market participant to reduce supply in response to weak demand the situation could be worse that today's oil prices less than half the peak price in mid-2014. No one wanted to see $10 oil prices. The Saudi's deserve credit for taking action, but blaming the US is a lot easier for the largest OPEC member than blaming other OPEC members for cheating yet again. The tough love OPEC action of holding production levels at their 30 million barrels per day punishes 3

OPEC members for cheating, punishing Russia for its duplicity, and starving Iran for its unconstructive rivalry as it seeks regional dominance in the Middle East.

This Saudi action is a solid triple hit, but it is not a home run and there will not likely be many runs batted in to pad the score when this game finally ends. The Saudi's did what they had to do in their own self-interest. They are furious at the Obama administration over its mishandling of Syria and Iran and the EU is similarly feckless.

The Saudi's need but do not trust Turkey and they worry that both Russia and China are not going to help the Saudi's achieve their own strategic interests.

The signals are getting stronger that the game of oil price chicken is running its course and likely will fade away as prices slowly rise to reflect slowly declining supply and flat demand by the end of 2015. Why?   

Because the Saudi's made their point about loss of market share and asserted 'adult supervision' of the market.

Because low oil prices also cost the Kingdom big money.

Because low oil prices hit OPEC members hard and some, like Venezuela and Ecuador are on budget life support.

China's economy is still slowing, the BRICs are broke, Russia is an angry bear starved for oil honey, and the US shale revolution has slowed down—-but if the Saudi really thought their policy would scuttle the onshore revolution in America they failed.

US production was sheltered by hedging and able to wind down drilling activity and rigs in an orderly way. But US shale producers also cut costs and their break-even points making their ability to cycle back up as prices rise along with demand. And because the Saudi's undermined the shale revolution elsewhere in the world it is time to declare victory even if it means that the US is still the best game in the world for access to reserves, to advanced technology, and to competitive advantage with lower break-evens for the future.

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What's all this appraisal business then?

Written by Stephen A. Brown from The Steam Oil Production Company Ltd Everyone knows the oil and gas value chain, I have drawn it for countless investor and strategy presentations, from my days in short trousers in BP's Corporate Planning Department to yet another roadshow presentation for investors. Here is one I had prepared earlier, no need to draw the picture yet again.

Note the drop shadows, very skeuomorphic, very early 2000's.

Working forwards it is all pretty obvious, first of all you get the acreage, then you explore - shoot seismic and drill a discovery well, boom success. That is the investment story of most E&P juniors, that is capital E and small p juniors.

Working backwards, it is pretty straightforward too, producing oil and gas is how most oil companies get their revenue, and developing discoveries (drilling wells and installing production facilities) is what you need to do to get production going. But what is that appraisal stage in the middle? That can't be all that important, surely the exploration company finds the oil and sells it on to a major who develops it.

Well not quite, in my opinion, after the moment the bit penetrates a reservoir for the first time and the geoscientists' dreams are put to the test, the appraisal stage is the most critical step in the whole process. It is where all the decisions are made that shape how profitable the development project will be. There is also a lot of money to be spent delineating the discovery and gathering the data that enables those decisions to be made.

That investment and the ingenuity that can go into shaping a development plan 5

explain why discoveries that change hands without a fully formed development plan are often valued from 50¢/bbl to $3 per barrel and those that have a good development plan, approved by the authorities and perhaps even financed, are valued significantly higher, from $4 to $10 per barrel or sometimes even more.

Transaction or market values for discovered but undeveloped oil and gas fields in the UKCS; value per barrel plotted against the oil price prevailing at the time the deal was struck; data from 2008 to 2015. Projects are fields which changed hands just before or just after government approval. Discoveries are fields which were sold well before government approval.

E&P company share prices often soar in the run up to the moment when the drillers get into the reservoir, only to slump if nothing is found or slowly sag, even if a discovery is made, as investors realise that there is a lot of work to do to get from a few dollars per barrel of value to the double figures that everyone hopes their discovery is worth.

The money invested in appraisal matters, it is $1 maybe $2 per barrel, for example 6

the wells drilled on our Pilot reservoir would cost at least $100 million if we had to drill them today, that's 70¢/bbl.

But I want to focus in on the ingenuity, the conceptualisation of the development plan. Why? Well, the reason for that is simple, that is the bit I love doing.

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1990 Harding development plan, gravity based concrete platform planned to be installed over Harding Central, many deviated production wells, Harding South developed using a subsea template. Seawater injection planned.

Let me tell you a story from 1991.

Are you sitting comfortably? Well, it seems a century ago now, but in those days I was working for BP, and I, along with David Madill and Hamid Khatib, were put in charge of the Harding development team not long after BP had bought Britoil. The field was called Forth then, after the river, as Britoil had liked to name their fields, but was renamed in honour of the late David Harding who was running BP Exploration in Europe when he passed away.

When we took over the project the field was really well appraised, lots of wells had been drilled and there was a top quality 3D seismic survey over the field. Truth be told, we didn't really have to gather more reservoir data. There was also a development plan, already in the works. It involved drilling lots of deviated wells from a concrete gravity based platform and Harding South was to be developed with subsea wells tied back to the main platform. Pressure support was planned to come from five injection wells which would have used sea water, though that was going to cause a lot of scaling problems. The only trouble was that it didn't quite meet the hurdle rate that BP had set for its projects back then, a 25% internal rate of return at $18/bbl. Those were the days.

So we looked at it this way and that; we knew we had to get the capital costs down, we thought we needed to cut 25% off the budget; it would help if we could get the recovery factor up as well. In conversation, we came up with an idea. I remember sitting with Hamid and Dave, drawing blobs on a whiteboard, we had the idea that if we could switch to horizontal wells (common place now, but not then) we could locate the platform between the two reservoirs, we would save all the subsea costs and maybe the horizontal wells would cost less and improve the sweep and the recovery factor. Then Colin Percival wandered past our office, scoffed at our target of 25% reduction and said - 'What are you going to do, saw off a leg and have a three legged platform!'.

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The approved Harding development plan, with fewer horizontal production wells, a TPG-500 drilling and production facility placed between the reservoirs and water source wells included.

Anyway, we decided we needed to prove we could actually drill and complete horizontal wells in the very unconsolidated sandstones in the Harding reservoir, and we went and asked for the money to do that. We also ran a design competition between the gravity based platform and the TPG-500, which had, you guessed it, three legs.

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Darn it, but didn't it all work out. The approved development plan was based on horizontal wells, drilled from a TPG-500 sitting on a concrete base. We also got our injection water from a shallow aquifer that didn't have any sulphate ions in the water so we solved our scaling issues as well.

The upshot was we flew over the hurdle rate and the net present value of the new development plan was four times the original plan. Not a bad result? The basic idea had taken an afternoon, and then about eighteen months to prove it all. And did horizontal wells help the recovery factor? Well, when we modelled it at the time we thought we could sweep up an extra 20 million barrels; it turns out we were being cautious - in fact by 2010 Harding Central had recovered 70% of the oil in place and the team working the field at that time planned to boost the recovery factor to 74%, one of the highest in the North Sea. Harding turned out to be a very successful, and credit to the project team, a very well executed, project, but its profitability was shaped on a wet afternoon in Glasgow and the reality is that getting the right concept for a development defines the value of the project.

Ingenuity and innovation need to be encouraged, but the industry struggles with any concept that isn't conventional and proven. In 1991 there hadn't been too many horizontal wells drilled in the North Sea and the idea of using a drilling and production jack-up was quite left field. I think we would have struggled to get our concept through the stage gate processes of today.

Those corporate processes are designed to batter risks out of projects but they often squeeze out innovative and profitable ideas too. But in the early nineties BP knew things had to be done differently to work and our management gave us the room to do that. If the UK is actually going to maximise recovery we need brave managements and investors willing to back ingenious ideas and novel development schemes.

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Deep Steam Written by Stephen A. Brown from The Steam Oil Production Company Ltd I wrote earlier about why 3,000' is considered the conventional limit for steam floods and this is a follow up note exploring some ways that the industry could increase that limit.

It has some significance; for the UK sector of the North Sea at least, we have estimated that, if you could push the limit down to 4,500', the incremental recovery possible could be more than 2 billion barrels of oil. Almost as much oil as in Johan Sverdrup, if that isn't worth thinking about what is?

In fact, people have been thinking about how to inject steam into deeper reservoirs for a long time. In 1977 the Department of Energy in the USA set up a five year programme, called 'Project Deep Steam' to develop downhole steam generators, thermal packers and insulated injection strings. That was all good stuff, but mostly focussed on reducing heat loss in the wellbore. However, if you can drill and complete wells into which you can inject around about 10,000 bbls/day of cold water equivalent of steam, then heat loss in the wellbore is a much smaller problem than you (or we) might have imagined.

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Given that most commentators see heat loss in the wellbore as the biggest hurdle to steam injection into deeper reservoirs, it may be that this realisation alone is reason enough to move the limit deeper for fields with high permeability reservoirs. In which case Statoil, Xcite et al should maybe skip the rest of this article and fire up their thermal reservoir simulators.

However there is another problem and that is the steam temperature, which increases with pressure. This plot shows the energy in steam versus pressure, you can also work out the water phase and by interpolating between the red isotherms, the temperature. Most steam floods aim to inject a mixture of steam and water with an enthalpy of between 2,000 and 2,500 kJ/kg. At 3000', for a normally pressured reservoir, that equates to 85 bar and 300ยบC. In fact it is equivalent to the top of the green box in the enthalpy diagram.

300ยบC is hot, but why does 300ยบC become a temperature limit? Well it doesn't have to be, but in sourcing potential completion equipment for the Pilot project we have found that there isn't a lot of downhole equipment available at temperatures this high.

Some components have been developed for the geothermal industry and have quite high temperature ratings but others lag behind. So far the highest rated packer we could find could cope with 540ยบC, but the best sliding sleeve was rated to 315ยบC.

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Looking at the enthalpy chart it seems as if temperature climbs very rapidly as pressure increases but while that is true to some extent, the effect is magnified by the fact that on this chart pressure is on a log scale. At 4,500' steam temperature for a normally pressured reservoir would be 338ยบC. Given that Schlumberger offer expansion joints and packers rated to 343ยบC it may well be that extending the depth limit is just a matter of trying it out with the right equipment in the wells and confirming that the temperature ratings are valid.

However, as we go deeper, the pressure increases, and the enthalpy of condensation decreases, what that means is that in the reservoir more of the swept zone will be occupied by, admittedly very hot, water and less by steam. The residual oil saturation for steam is less than that for hot water at the same temperature so we would lose some of the possible benefit of steam flooding. That might turn out to be a marginal effect, but it would probably be better if we could find a way to keep more of the fluid we inject into the reservoir in the gas phase.

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Co-injecting a non-condensible gas would do just that and as that would also reduce the partial pressure of the steam it would also reduce the steam temperature. But perhaps a better alternative is to co-inject a fluid which is miscible at reservoir conditions. That seems to be a promising approach in its own right: adding about 5% propane or butane to the injected steam can accelerate oil production and reduce the amount of steam which has to be injected by about 30%. There are many trials of this technique underway in Canada.

In fact there seem to be multiple avenues for investigation of what could be the best steam injection strategy for deeper reservoirs, and all of them seem quite promising.

Of course not all deeper heavy oil fields will be perfect for steam flood, some have bottom water which can act as a thief to the heat one is trying to inject into the reservoir. But with the advent of horizontal wells with steam injection valves along the wellbore, much more precision in the placement of steam is possible than in the past. That gives us many more tools to control where the heat goes so steam injection could well be feasible in many more fields than people have realised.

If a steam flood is feasible it is best done right from the start of production; all the time and energy expended in performing a conventional waterflood before doing a steam flood is wasted, so best to crank up that reservoir model now. Alternatively, as a first step, come and talk with us about proving that steam flood can work offshore on the one North Sea field that is shallow enough to pass all the conventional screening criteria.

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OPEC hit as 'peak oil demand' arrives and US imports fall Written by Paul Hodges from ICIS

Oil market traders have been having fun in recent weeks, as they have managed to create guaranteed price movements every week: 

US oil inventory data is published on Tuesday and Wednesday



This gives traders the chance to push prices lower as the inventories continue to rise US oil rig data is published on Friday This creates the chance to push prices higher again as the number of working rigs falls In turn, this volatility also creates great opportunities for media coverage, further boosting trading interest.

  

However, in the real world, these trading games are simply a distraction. Far more important is the massive change underway in world oil markets, as highlighted in the above chart of US oil imports:

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   

It shows US crude oil and product imports since 1993, and confirms these peaked in 2006 at 14.7mbd Since then, they have fallen by more than a third to just 9.3mbd (green line) OPEC has been the big loser, with its exports down nearly 2/3rds from 6.4mbd to 2.4mbd (orange) Critically, Canada's exports have been higher than OPEC's since May last year (red)

These developments are naturally being ignored by the traders. But they go a long way to explaining why market share has become the prime objective for most oil exporters, as discussed in October's pH Report, 'Saudi Arabia needs much lower oil prices'.

Equally important is that the world is now arriving at 'peak oil demand'. As a new Bloomberg analysis confirms: 'Saudi leaders have worried for years that climate change and high crude prices will boost energy efficiency, encourage renewables, and accelerate a switch to alternative fuels such as natural gas, especially in the emerging markets that they count on for growth. They see how demand for the commodity that's created the kingdom's enormous wealth—and is still abundant beneath the desert sands—may be nearing its peak....'

Oil Minister Naimi told reporters in Qatar three years ago, 'Demand will peak way ahead of supply.'

Plus, of course, demographic shifts are already reducing US gasoline demand, as I noted last month:   

Average per capita miles driven have fallen 8.4% since 2004 Older people no long act as a taxi service for their children, and stop driving to work when they retire Millennials (those born between 1983-2000) have far less interest in driving than their parents

A further headwind for demand growth is highlighted by the US Energy Information Agency's new Annual Report: 'The need for imports will further decline after 2020 as increased vehicle fuel economy standards limit growth in domestic demand.'

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Saudi Arabia is clearly not being distracted by the oil traders' temporary excitement It knows it would risk being marginalised if it continued with the previous policy of cutting production to support prices. As Naimi noted last month: 'Saudi Arabia cut output in the 1980s to support prices. I was responsible for production at Aramco at that time, and I saw how prices fell. So we lost on output and on prices at the same time,' al-Naimi said. 'We learned from that mistake.'

Weekly Market Round-Up My weekly round-up of Benchmark prices since the Great Unwinding began is below, with ICIS pricing comments: 

 

   

Benzene Europe, down 42%. 'There have been more exports out of Europe across the Atlantic since the end of March, helping to balance out the length seen on benzene since the start of the year' Brent crude oil, down 41% Naphtha Europe, down 36%. 'Naphtha demand from the petrochemical sector is being undermined by cheaper propane, which is seen as the better feedstock' PTA China, down 33%. 'Prices were largely firmer owing to price gains seen in the upstream crude futures and feedstock paraxylene (PX) markets' HDPE US export, down 23%. 'Domestic export prices stayed the same' ¥:$, down 16% S&P 500 stock market index, up 6%

Paul Hodges is a blogger for ICIS, the independent energy price reporting agency, and chairman of International eChem, trusted advisers to the chemical industry and its investment community.

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Putting the Real Story of Energy and the Economy Together Written by Gail Tverberg from Our Finite World

What is the real story of energy and the economy? We hear two predominant energy stories. One is the story economists tell: The economy can grow forever; energy shortages will have no impact on the economy. We can simply substitute other forms of energy, or do without.

Another version of the energy and the economy story is the view of many who believe in the 'Peak Oil' theory. According to this view, oil supply can decrease with only a minor impact on the economy. The economy will continue along as before, except with higher prices. These higher prices encourage the production of alternatives, such wind and solar. At this point, it is not just peak oilers who endorse this view, but many others as well.

In my view, the real story of energy and the economy is much less favorable than either of these views. It is a story of oil limits that will make themselves known as financial limits,quite possibly in the near term—perhaps in as little time as a few months or years. Our underlying problem is diminishing returns—it takes more and more effort (hours of workers' time and quantities of resources), to produce essentially the same goods and services.

We don't measure our investment results with respect to the quantity of end product produced (barrels of oil produced, liters of fresh water produced, kilos of copper produced, or number of workers provided with sufficient education to work in high tech industries), so we don't realize that we are becoming increasingly inefficient at producing desired end products. See my post 'How increased inefficiency explains falling oil prices.'

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Wages, viewed in terms of the product produced-oil in this case-can be expected to decrease as well. This change isn't evident in usual efficiency statistics, because some of the workers are providing new kinds of services, such as fracking services, that weren't required before.

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Even investment is becoming increasingly inefficient. It takes more and more investment to extract a given quantity of oil or other energy product. This investment needs to stay in place longer as well. The ultra-low interest rates we have been experiencing reflect the poor returns investments are now making.

The myth exists that prices of all of the scarce goods and services will rise high and higher, as the economy encounters scarcity. The real story, though, is that the inflation-adjusted purchasing power of common workers is falling lower and lower, especially in the United States, Europe, and Japan. Not only can these workers afford to buy less, but they can also afford to borrow less. This means that their ability to purchase expensive goods created from commodities is falling.

At some point, this lack of purchasing power can be expected to affect the financial markets, and the prices of many commodities can be expected to fall. In fact, this already seems to be happening.

The likely impact of such a fall in commodity prices is not good. If low oil prices cannot be 'turned around,' they will lead to debt defaults, and these debt defaults are likely to lead to failing financial institutions. Failing financial institutions have the potential to bring down the system, because it becomes very difficult for businesses to continue if they are not supported by a banking system that allows a company to pay its employees. Workers also need the banking system to pay for goods and to save for a 'rainy day.'

A big part of what has allowed the economy to grow to the size it is today is increasing debt levels. These rising debt levels play many roles: 

They make high-priced goods more affordable to consumers.



They create greater demand for goods, allowing more end-product goods to be produced.

They create more demand for commodities required to make end-product goods, allowing the price of these commodities to rise, so that more businesses have more incentive to create/extract these commodities.



At some point, debt levels stop rising as fast as they have in the past (because of a lack of growth in purchasing power because of diminishing returns in investment), and the whole system tends to fall toward collapse. We seem to have reached this point in the middle of 2014. China was raising its total debt level rapidly up until the

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early part of 2014, then suddenly moderated its growth in debt level in mid 2014. At about the same time, the US scaled back and eliminated it program of quantitative easing (QE). Oil prices dropped starting in mid-2014, at the time debt levels started moderating. Other commodity prices started falling as early as 2011, indicating likely affordability problems.

We are now in the period when many people still believe everything is going well. Oil prices and other commodity prices are low—what is 'not to like'? The answer is that the system in not at all sustainable—profits of oil companies and other commodity businesses are down, just as wages of common workers in developed countries are down in inflation-adjusted terms. Companies are cutting back in investment in oil production. Soon oil production will drop. With lower oil supply, the economy will face huge challenges.

Many people believe that oil prices can bounce back up again, but this really isn't the case, because of growing inefficiency related to limits we are reaching-the need to use more advanced techniques to produce oil; the need for desalination for water in some places; the need for more pollution control equipment that doesn't really increase the finished goods and services we are producing but instead makes goods more expensive to produce.

Each worker is, on average, producing less and less of the finished goods we really need. Whether we like it or not, standards of living will have to fall. The amount of debt workers can afford decreases rather than increases. This new reality can be expected to manifest itself in debt defaults and increasing financial system problems.

Even if oil prices bounce back up again, it is doubtful that shale oil drillers will be able to again borrow at a sufficiently high rate to increase their production again—what lender will believe that oil prices will remain high indefinitely?

The China Connection I have trying to put the real story of energy and the economy over a period of years.

Prof. Lianyong Feng of Petroleum University of China, Beijing, hired me to put together a short course (eight sessions, each lasting about 1.5 hours) on the nature of our current problems for students majoring in 'Energy Economics and Management.' The course would be open to everyone choosing this major, including freshman, so I needed to assume a fairly low level of background knowledge. Actual 21

attendees included a number of graduate students and faculty, attending the course without credit.

I put together a series of lectures, which I gave during the second half of March 2015. PDFs of my lectures are also now available on my Presentations/Podcasts page.

These lectures were videotaped by Prof. Feng's staff, and I am in the process of making You Tube Videos from them, in addition to the original MP4 format.

(YouTube videos cannot be seen in China.) My current plan is to give a brief discussion of these lectures, in future posts.

Following the lecture series, I visited several places in China, to see how the economic slowdown is playing out in China. This included visits to Northwest China (Hohhot and Hardin), Northeast China (Daqing and Harbin), and Southeast China (Wenzhou area). In Wenzhou, I visited three different companies attempting to sell electrical equipment on the world market.

From these visits, we could see how the world economic slowdown is affecting China, and how China's own slowdown in debt growth is adding to the world slowdown. We could also see that the slowdown has not yet run its course Chinagrowth in housing continues, even as the need for it seems to be slowing. College students are finding it difficult to find high-paying jobs in oil and other commodity sectors. The lack of growth in high-paying jobs will provide downward pressure on housing prices as well.

I plan to write a post about this situation as well.

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Oil Price Rally Built On Very Fragile Ground Written by John Richardson from ICIS

Oil prices rallied yesterday on an unexpected fall in inventories at Cushing in the US to 61.7 million barrels for the week ending 24 April (see the above chart). This was a decline of 514,000 barrels over the previous week, which compared with forecasts of an increase of 400,000 barrels.

So does mean that supply is finally responding to lower prices, resulting in a 'New Normal' of crude trading in a pretty stable range of $50-70 a barrel, or perhaps even higher?

No. As a Singapore oil trader who I spoke to this morning put it: 'Whoopee, Cushing has declined, but this is only partly because US refinery operating rates picked up a little.

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'And the other reason that Cushing storage fell was that it was almost at maximum capacity. In other words, it hadn't much further to go except down.

'You must also put this decline in to the context of oil inventories across the whole of the US. According to the latest Energy Information Administration report, total US crude stocks are still at their highest level in more than 80 years,' he said (see the chart below).

'US oil production also rose by 7,000 barrels last week, and it now at its highest level for several decades,' the trader continued.

American shale-oil production is now at around 4 million barrels a day, up from 1.2 million barrels a day last year.

So why did yesterday see West Texas Intermediate hit $58.58 a barrel, its highest price since 11 December 2014?

Perhaps because of financial speculation. Data shows that in the case of Brent, hedge funds have placed huge bets on higher prices by taking out futures 24

options worth 265 million barrels of oil - yet another all-time high. Commodity markets often move on sentiment, and the sentiment amongst the speculators seems very bullish at the moment.

But as the Singapore trader pointed out, there is plenty of data out there to suggest that this price rally has been built on very fragile ground.

And here are six more important points to consider: 1. Oil producers have hedged more than 500 million barrels of Brent in order to protect against further price declines. Their ability to so do might well have been helped by the extra liquidity in futures markets provided by the hedge funds. So this means that the producers can now afford to stomach muchlower H2 prices in physical markets because they have locked-in higher prices on futures markets. This could result in oil production remaining high in the second half of this year, even if physical prices do suffer another sharp downward correction.

2. The view of the oil producers is opposite to that of the hedge funds.

ExxonMobil CEO Rex Tillerson, for example, said last week that there would be no quick rebound to higher prices. Exxon is the largest shale producer in the US. Last week also saw the CEO of ConocoPhillips, John Watson, say that he was worried that there were too many US untapped shale-oil awaiting completion. This is the 'fracklog' I discussed last month. So recent stronger pricing might be quickly reversed by these wells being brought on-stream.

3. US shale producers are expected to see their costs fall by 45% this year, and by up to 70% by the end of next year, according to the UK's Daily Telegraph.

Hess, for example, has announced it has already 'driven down drilling costs by 50%, and we can see another 30% ahead.' This underlines my point that the US has huge incentives, both economic and political, to continue working very hard to reduce shale-oil production costs.

4. Oil companies in general, not just shale oil companies, are treating lower prices as an opportunity to trim costs - and thus lower their production costs.

They are finding these savings in rig rates, the cost of equipment, well completions and other oil services.

5. Almost all countries can still economically produce oil at $15 a barrel, according to a new IMF and Rystard Energy Study. Only Canada/Australia with costs of $20 a barrel, Brazil at $30 a barrel and the UK at $40 a barrel needed higher prices, added the study. 'Lower oil prices are expected to have 25

a smaller impact on production of shale oil in the United States than on deepwater and oil sand production, especially in Brazil, Canada, and the United Kingdom,' wrote the IMF. 6. Saudi Arabia is playing the long game in order to try and win back market share, and so is unlikely to cut production. There used to be a lot of talk of Saudi Arabia needing oil at around $90 a barrel to balance its budget. But this overlooked the fact that Saudi Arabia has plenty of foreign reserves to enable to withstand prices at much-lower levels for several year. And, anyway, Saudi Arabia remembers the bitter lesson of the 1980s, when its production cutbacks failed to prevent oil prices from falling - because other countries maintained or increased their output.

7. US dollar strength. A stronger dollar means that recent price declines are having less of a beneficial impact on other countries because they have, of course, seen their local currencies weaken against the Greenback. This has reduced the demand for oil.

And there is an eighth factor worth separate mention, as it is the most important factor of all, which is this: Demand. Apart from the impact of a stronger dollar on oil consumption, the global economy continues to struggle, largely because of events in China.

So as I again think about the hard-pressed chemicals company planning offices out there, here is some concluding advice: Please, please build in a scenario of a sharp retreat in oil prices in the second half of this year.

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How did that prediction work out, Nostradamus?

Written by Stephen A. Brown from The Steam Oil Production Company Ltd They say never make predictions, especially about the future; and by 'they' I mean just about everyone, the quote is variously attributed to Yogi Berra, Albert Einstein and Dan Qualye, amongst others.

Foolishly I ignored that advice and I did make a prediction, but I did have a little edge, I paid attention to that other quote about learning from history. At the beginning of February I wrote an article predicting that oil production growth in six American states would stall in the summer, the six states I had settled on were the ones which have been behind the amazing climb in US oil production, Texas, North Dakota, Oklahoma, New Mexico, Utah and Colorado.

Well, it isn't the summer yet, but it is April, and one of the things I also said in that article was that I reckoned the number of rigs working in those six states would have fallen to 700 by April. I just counted them up in the Baker Hughes rig count published on 20th April, the tally of rigs working in those states was as follows: Texas - 411, North Dakota - 83; Oklahoma - 118; New Mexico - 49; Utah - 7; Colorado - 36. That's a total of 704, so I claim some success with that prediction. Not quite good enough to ask Nostradamus to vacate the premises but a decent start.

But the only reason to make that prediction was to try to project what would happen to oil production. Sadly the data on a state by state basis is only released by the EIA on a monthly basis, and the latest data release only runs to January 2015. Still that is a couple more months worth of data than when I made the prediction; at first glance it looks like I was a bit slow in saying it would take to the summer for oil production in those six states to start to fall, the January production figure of 5.743 mmbbls/day is some 38,000 bbls/day down on December. However, when you look at the weekly data and the monthly actual and forecast data, which is only available for US oil production as a whole, you can see that January was a head fake, and that the February and March figures will probably be ahead of January by a couple of hundred thousand barrels per day.

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The teenage scribblers on Wall Street will have a field day with that news when it comes out, doubtless bragging about the resilience of the US shale industry and predicting doom and gloom for oil prices. But it will be no surprise and it tells us nothing we don't already know - it takes months and months for the impact of slashed capital expenditures to be felt.

But, look closely at the yellow line and you can see that there is a hint that supply growth is just beginning to stall. I am now pretty certain that by the height of summer we will be getting data that confirms that US production has started a decline. How steep that decline will be I don't honestly believe anyone knows. The EIA project a pretty gentle decline (the blue line), but shale production has a different character to any conventional reservoir and I suspect that we might close out 2015 with overall US production below, rather than above, 9 mmbbls per day.

We can check in again on that prediction in early 2016.

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US jobs growth stalls as shale gas bubble ends Written by Paul Hodges from ICIS

Apparently Friday's US jobs numbers disappointed the experts. The consensus forecast was that 250k jobs would have been created in March - yet only half the forecast actually appeared. Even more tellingly, hiring estimates for January/February were revised down. Separate data also showed weak growth in wages and spending.

None of this was really a surprise, however. There was plenty of evidence that US employment had simply seen a temporary boost from the shale gas bubble.

My 8 January post was even headlined 'US jobs growth at risk with end of the shale gas advantage', and was followed a week later by a post titled 'US economic recovery at risk as energy bubble bursts'. All the necessary data was easily available in the public domain, if anyone wanted to look.

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But as during the subprime era, the consensus simply didn't want to know. It was much easier to pretend to believe that somehow printing money could change the fundamentals of the US jobs market. But at the risk of repeating myself, the key data continues to be found in charts 16 and 17 of the Bureau of Labor Statistics monthly report, as shown above:    

US employment rates depend on race (chart 16) and educational level (chart 17) The jobless rate for Blacks (10.1%) is double that for Whites (4.7%) and Asians (3.1%), and 50% higher for Hispanics (6.8%) The rate for those without a high school diploma (8.6%) is 3x that for those with a bachelor's degree (2.5%) The rate for those with a high school diploma (5%) is still double that of those with a degree

The issue is rather, as I noted back in September, that politicians prefer to ignore these structural problems in the economy. It is much easier to instead simply tweet about the need for more stimulus, and then deliver a sound-bite on the subject for the evening news bulletin.

The news is also embarrassing for the US Federal Reserve. They have spent nearly 2 years preparing to celebrate the success of their stimulus policies, since the 'taper tantrum' - when then Fed Chairman Ben Bernanke suggested in May 2013 the Fed would soon be able to 'normalise' its policies.

But now that oil prices are returning to their historical relationship to natural gas, in terms of energy value, the bubble is ending. And unfortunately, it is taking with it the highly paid jobs that the bubble had created.

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Q1 2015 Oil & Gas M&A tumbles to $7.1 billion in E&P sector Written by Eoin Coyne from Evaluate Energy Buyers and Sellers Reach Impasse on the Value of Assets The value of global upstream oil and gas M&A deals tumbled to $7.1 billion during Q1 2015, a drop of 79% compared to the value in Q1 2014 and a drop of 85% compared to the average value per quarter since the start of 2009. The oil price as per the WTI benchmark started the year at $52 and has moved little since. With Saudi supply policy showing no signs of shifting, large U.S. stock inventories persisting and further supply side pressure from a potential resolution to sanctions on Iranian exports, the chances of a sharp increase in oil price in the near future are slim.

Source: Evaluate Energy

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In the medium-to-long term commodity prices will inevitably return to a semblance of levels seen in the past 5 years as cuts in exploration and development drilling translates into a restoration in the oil price, closer to the required break-even level to sanction new development projects. For any well-capitalized company, this quarter could have been seen as a rare opportunity to acquire oil assets at a steep discount to historical levels. However, with sellers seemingly of an opinion that the oil price is lower than fair value, an impasse has been reached, resulting in the lowest value quarter for oil and gas deals in the 7 years that Evaluate Energy has been tracking all global oil and gas transactions.

Private Companies Active Despite Price Downturn In times such as these, when the outlook for earnings is poor, it is advantageous to be free from the burden of satisfying a large group of shareholders demanding quick fixes to what will very likely be a cyclical downturn requiring patience. For this reason, private companies have become relatively more prominent during this quarter in the M&A market. Over the past 5 years, private companies have accounted for 10% of the total publicly disclosed oil and gas deal value. In Q1 2015, however, private companies accounted for $4.1 billion of corporate and asset acquisitions, representing a significant 58% of the total global deal value.

In addition to the corporate and asset acquisitions, private equity companies also made inroads into the oil and gas sector via less traditional methods. The largest of these involved Quantum Energy Partners, who agreed a $1 billion deal with Linn Energy for a 'Strategic Acquisition Alliance,' which will see Quantum initially committing up to $1 billion of capital to leverage Linn Energy's experience in acquisitions whilst allowing Linn to maintain its momentum in what would have otherwise likely have been a time of cutbacks for the debt-laden company. EIG Global Energy Partners also invested $1 billion into the U.S. oil patch via the acquisition of $350 million worth of preferred units of Breitburn Energy Partners and the issuance of $650 million of senior secured notes.

Shale Suffers Worst Quarter for 5 Years The shale industry in North America was strongly cited as one of the chief instigators of the falling oil price and now that the price has settled around $50 it has been one of the first sources of supply to be hit. The comparatively short life cycle of shale wells makes this industry sensitive to short term economics and dramatic changes 32

are already being seen. Whereas 12 months ago oil and gas companies were clamouring to secure rigs to drill new wells in oil plays, many of those rigs are now sitting redundant. The oil rig count in the Bakken has dropped 51% from 185 in Q4 2014 to 91 in the first week of April 2015, likewise rigs in the Eagle Ford play have dropped 31% from 199 to 137 in the same time frame. The effect of the price downturn on M&A in the shale industry has been a quarter with the lowest amount of shale deals since Q1 2009 of $0.4 million, compared to an average quarterly value of $8.9 million over the past 5 years.

Nigeria Sees Surge in Deals In contrast to the rest of the world, Nigeria experienced a surge in deals during the quarter with a total value encompassing 40% of the global value. With the Nigerian federal government pushing for an increase in ownership of the country's resources for indigenous companies, three deals were announced by Nigeria-based companies for OML 29, OML 53 and OML 55 for a total of around $2.9 billion. Aiteo Ltd. acquired a 45% interest in OML 29 from Royal Dutch Shell, Total and ENI for $2.55 billion, while SEPLAT acquired a 40% interest in OML 53 from Chevron for $256 million and a 22.5% interest in OML 55 for $132 million from Belema Oil Producing Ltd. The long history of troubles for Western companies in Nigeria may have resulted in many of these assets being labeled as problem assets, but the fact that Shell, Total and ENI have received a consideration that was apparently unaffected by the fall in oil price will have gone some way to mitigate these past struggles. Lastly, Mart Resources Inc., a Canadian-listed company with assets in Nigeria was acquired by Midwestern Oil and Gas Company Ltd. for $365 million.

Whitecap Makes Largest Deal by a Public Company The largest deal by a public company during the quarter came from Whitecap Resources Inc., who acquired Beaumont Energy Inc. for US$462 million. Whitecap had room to manoeuvre following US$500 million of equity issuances during earlymid 2014, a time when the share prices of oil and gas companies were still strong, leaving its debt-to-capital-employed at a healthy level of 23%. With this acquisition, Whitecap will be building on its existing operations in the Viking area of Saskatchewan at a price of sub-$15 per proved and probable barrel of oil equivalent.

The deal structure was 70% weighted towards stock, meaning that Whitecap will still be in a position to consolidate its operations following closure should any further opportunities arise.

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Outlook Even though the oil price is resting at attractive levels right now for buyers, it's clear that this quarter has come too early for many to make opportunistic acquisitions.

Companies will doubtless feel the squeeze as time goes by and Q2 2015 will inevitably be a time when we see an increase in distressed sales as debt-laden companies have their hands forced by the need to furnish debt.

Assuming that a debt-to-capital-employed level of 35% is still a healthy level to operate within, the table below shows the top ten global oil and gas companies that are in a position to make opportunistic acquisitions (data taken from Evaluate Energy's financial and operating database as per year end 2014 financial accounts click here to find out more).

Source: Evaluate Energy. NOTE: Since the time of writing this article the 2nd ranked company, Royal Dutch Shell, made an offer to acquire BG for $80 billion.

Top 10 Deals During Q1 2015

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Source: Evaluate Energy Notes 1. All $ values refer to US dollars 2. All data here is taken from the Evaluate Energy M&A database, which provides Evaluate Energy subscribers with coverage of all E&P asset, corporate and farm-in deals back to 2008, as well as refinery, LNG, midstream and oil service sector deals.

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What Iranian Supply Overhang?

Written by Stephen A. Brown from The Steam Oil Production Company Ltd Sometimes I really wonder how na誰ve people are.

Everyone is expecting oil to flood onto the market if the US agrees a deal on the Iranian nuclear programme and eases sanctions on Iran. I read that Iran is storing 30 million barrels of oil at sea as sanctions keep a lid on sales. I am quite sure that Iran has 30 million barrels of oil at sea but for those people who believe that Iran has meekly shut in production because of sanctions, well for you I have a bridge at the bottom of my garden which I would love to sell you.

London Bridge, Lake Havasu City, Arizona, Photo Ken Lund from Las Vegas, Nevada, USA 36

The reality is that sanctions do hurt Iran, they still produce and export their oil, no matter what the charts and official data say, but right now there are middlemen to be paid and logistical challenges to overcome to rebrand the 'Country-of-Origin' of the oil that, I believe, still makes its way onto the market. It happened during the Iraq 'Oilfor-Food' programme and for sure it is happening now. All it takes is a comfortable arrangement with some friends in the marketing arm of a flexible oil ministry somewhere that does actually produce oil and where auditing processes aren't quite as precise as, say, in the UK. Of course the ultimate buyer has to be a little flexible too as they need to be happy to get a cargo which isn't quite what it says on the tin.

But for a fee of $5/bbl and a discount of $10/bbl you can get a lot of flexibility on a one million barrel cargo.

I have even had the misfortune to do business with some people who would be able to help you out if you needed some of that flexibility.

So yes, Iran wants the sanctions lifted, they would rather get full price for their oil, and for sure there are 30 million bbls of oil on the high seas waiting for the sanctions to lift, but that is the extent of the oil about to flood onto the market; you know, an afternoon's worth of world oil consumption. There aren't wells shut in waiting to be produced, they are all online already. In the long run more companies will be able to invest in Iran and eventually that might boost Iranian production, but negotiating investment deals in Iran is mostly an exercise in frustration, so it will take a long time to make a significant difference to global oil production.

Now, about that bridge‌

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